0001276187us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMemberus-gaap:CashAndCashEquivalentsMemberus-gaap:FairValueInputsLevel2Member2022-12-31
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Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ýý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 2022
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
et-20221231_g1.jpget-20221231_g1.jpg
ENERGY TRANSFER EQUITY, L.P.LP
(Exact name of registrant as specified in its charter)
Delaware30-0108820
(stateState or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)code:(214) 981-0700
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsETNew York Stock Exchange
7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred UnitsETprCNew York Stock Exchange
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred UnitsETprDNew York Stock Exchange
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred UnitsETprENew York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ý    No  ¨
Yes  ý    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  ¨    No  ý
Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ý    No  ¨
Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company”company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  ý    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨ ☐Emerging growth company  ¨☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ý
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ¨
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  ¨☐  No  ý
The aggregate market value as of June 30, 2017,2022, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such Common Units on the New York Stock Exchange on such date, was $14.11$26.73 billion. Common Units held by each executive officer and director and by each person who owns 5% or more of the outstanding Common Units have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
At February 16, 2018,10, 2023, the registrant had 1,079,145,5613,094,593,760 Common Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None


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Index to Financial Statements
TABLE OF CONTENTS
 
PART I
PAGE
ITEM 1.
6
PAGE
ITEM 1.1A.
147
ITEM 1A.1B.
34
ITEM 1B.
UNRESOLVED STAFF COMMENTS
7091
ITEM 2.
7092
ITEM 3.
7092
ITEM 4.
7395
PART II
ITEM 5.
7496
ITEM 6.
7597
ITEM 7.
7697
ITEM 7A.
117126
ITEM 8.
120129
ITEM 9.
120129
ITEM 9A.
120129
ITEM 9B.
122131
ITEM 9C.
131
PART III
ITEM 10.
123132
ITEM 11.
128138
ITEM 12.
142154
ITEM 13.
144155
ITEM 14.
145156
PART IV
ITEM 15.
147157
ITEM 1616.
148158

152166
 



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Index to Financial Statements

Definitions
The following is a list of certain acronyms and terms used throughout this document:
/dper day
Adjusted EBITDAa non-GAAP measure defined as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, as further described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations”
AOCIaccumulated other comprehensive income
AROsasset retirement obligations
BBtubillion British thermal units
Bcfbillion cubic feet
BtuBritish thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
Capacitycapacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
CitrusCitrus, LLC, a 50/50 joint venture which owns FGT
Dakota AccessDakota Access, LLC, a non-wholly-owned subsidiary of Energy Transfer
DOEUnited States Department of Energy
DOJUnited States Department of Justice
DOTUnited States Department of Transportation
EnableEnable Midstream Partners, LP, a Delaware limited partnership
Energy Transfer CanadaEnergy Transfer Canada ULC, a non-wholly-owned subsidiary of Energy Transfer until its sale in August 2022
Energy Transfer GC NGLEnergy Transfer GC NGLs LLC, formerly Lone Star NGL LLC, a wholly-owned subsidiary of Energy Transfer
Energy Transfer Preferred UnitsCollectively, the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Series H Preferred Units
Energy Transfer R&MEnergy Transfer (R&M), LLC (formerly Sunoco (R&M), LLC)
EPAUnited States Environmental Protection Agency
ETC SunocoETC Sunoco Holdings LLC (formerly Sunoco, Inc.), a wholly-owned subsidiary of Energy Transfer
ETOEnergy Transfer Operating, L.P., formerly a non-wholly-owned subsidiary of Energy Transfer until its merger into the Partnership in April 2021
ETP HoldcoETP Holdco Corporation, a wholly-owned subsidiary of Energy Transfer
Exchange ActSecurities Exchange Act of 1934, as amended
ExplorerExplorer Pipeline and/or Explorer Pipeline Company
FEPFayetteville Express Pipeline LLC
FERCUnited States Federal Energy Regulatory Commission
FGTFlorida Gas Transmission Pipeline and/or Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus
GAAPaccounting principles generally accepted in the United States of America
General PartnerLE GP, LLC, the general partner of Energy Transfer
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HFOTCOHFOTCO LLC, a wholly-owned subsidiary of Energy Transfer, which owns the Houston Terminal
IDRsincentive distribution rights
IFERCInside FERC’s Gas Market Report
IRSUnited States Internal Revenue Service
Lake Charles LNGLake Charles LNG Company, LLC, a wholly-owned subsidiary of Energy Transfer
Lake Charles LNG ExportLake Charles LNG Export Company, LLC, a wholly-owned subsidiary of Energy Transfer
LIBORLondon Interbank Offered Rate
LNGliquefied natural gas
MBblsthousand barrels
MEPMidcontinent Express Pipeline LLC
Mid-ValleyMid-Valley Pipeline Company, a wholly-owned subsidiary of Energy Transfer
MMBblsmillion barrels
MMcfmillion cubic feet
MTBEmethyl tertiary butyl ether
NGANatural Gas Act of 1938
NGLnatural gas liquid, such as propane, butane and natural gasoline
NGPANatural Gas Policy Act of 1978
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
ORSOhio River System LLC, a non-wholly-owned subsidiary of Energy Transfer
OSHAFederal Occupational Safety and Health Act
OTCover-the-counter
PanhandlePanhandle Eastern Pipe Line Company, LP, a wholly-owned subsidiary of Energy Transfer
Partnership AgreementEnergy Transfer’s Third Amended and Restated Agreement of Limited Partnership, as amended to date
PCBspolychlorinated biphenyls
PEPPermian Express Partners LLC, a non-wholly-owned subsidiary of Energy Transfer
PHMSAPipeline Hazardous Materials Safety Administration
Preferred UnitholdersUnitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Series H Preferred Units, collectively
RoverRover Pipeline and/or Rover Pipeline LLC, a non-wholly-owned subsidiary of Energy Transfer
SCOOPSouth Central Oklahoma Oil Province
Sea RobinSea Robin Pipeline and/or Sea Robin Pipeline Company, LLC, a wholly-owned subsidiary of Energy Transfer
SECUnited States Securities and Exchange Commission
Series A Preferred Units6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series B Preferred Units6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series C Preferred Units7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series D Preferred Units7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series E Preferred Units7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series F Preferred Units6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series G Preferred Units7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series H Preferred Units6.500% Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
SESHSoutheast Supply Header Pipeline and/or Southeast Supply Header, LLC
SOFRSecured overnight financing rate
Southwest GasPan Gas Storage, LLC (d.b.a. Southwest Gas Storage Company), a wholly-owned subsidiary of Energy Transfer
SPLPSunoco Pipeline L.P., a wholly-owned subsidiary of Energy Transfer
TigerTiger Pipeline and/or ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of Energy Transfer
TranswesternTranswestern Pipeline and/or Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of Energy Transfer
TRRCTexas Railroad Commission
TrunklineTrunkline Gas Company, LLC, a wholly-owned subsidiary of Energy Transfer
UnitholdersPreferred Unitholders and holders of Energy Transfer LP common units
USACUSA Compression Partners, LP, a publicly traded partnership and consolidated subsidiary of Energy Transfer
White CliffsWhite Cliffs Pipeline, L.L.C.
Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P.LP (the “Partnership” or “ETE”“Energy Transfer”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “could,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated, projected, forecasted, expressed or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Item 1.A1A. Risk Factors” included in this annual report.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
5
/dper day
AlohaAloha Petroleum, Ltd
AmeriGasAmeriGas Partners, L.P.
AOCIaccumulated other comprehensive income (loss)
AROsasset retirement obligations
Bblsbarrels
BBtubillion British thermal units
Bcfbillion cubic feet
BtuBritish thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
Capacitycapacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
CDMCDM Resource Management LLC
CDM E&TCDM Environmental & Technical Services LLC
CitrusCitrus, LLC which owns 100% of FGT
CrossCountryCrossCountry Energy, LLC
Dakota AccessDakota Access, LLC
DOEUnited States Department of Energy
DOJUnited States Department of Justice
DOTUnited States Department of Transportation
Eagle RockEagle Rock Energy Partners, L.P.
ELGEdwards Lime Gathering, LLC
EPAUnited States Environmental Protection Agency
ETC FEPETC Fayetteville Express Pipeline, LLC
ETC MEPETC Midcontinent Express Pipeline, L.L.C.

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Index to Financial Statements
ETC OLPLa Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
ETCOEnergy Transfer Crude Oil Company, LLC
ETGEnergy Transfer Group, L.L.C.
ETE HoldingsETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
ETPEnergy Transfer Partners, L.P.
ETP GPEnergy Transfer Partners GP, L.P., the general partner of ETP
ETP HoldcoETP Holdco Corporation
ETP LLCEnergy Transfer Partners, L.L.C., the general partner of ETP GP
ETP Convertible Preferred UnitsETP’s Series A Convertible Preferred Units
ETP Series A Preferred UnitsSeries A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETP Series B Preferred UnitsSeries B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Exchange ActSecurities Exchange Act of 1934
ExxonMobilExxon Mobil Corporation
FDOT/FTEFlorida Department of Transportation, Florida’s Turnpike Enterprise
FEPFayetteville Express Pipeline LLC
FERCFederal Energy Regulatory Commission
FGTFlorida Gas Transmission Company, LLC, which owns a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula
GAAPaccounting principles generally accepted in the United States of America
General PartnerLE GP, LLC, the general partner of ETE
HPCRIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
IDRsincentive distribution rights
KMIKinder Morgan Inc.
Lake Charles LNGLake Charles LNG Company, LLC
LCLLake Charles LNG Export Company, LLC
LIBORLondon Interbank Offered Rate
LNGliquefied natural gas
LNG HoldingsLake Charles LNG Holdings, LLC
Lone StarLone Star NGL LLC
LPGliquefied petroleum gas
MACSMid-Atlantic Convenience Stores, LLC
MBblsthousand barrels
MEPMidcontinent Express Pipeline LLC
Sunoco Logistics MergerThe merger of Sunoco Logistics with and into ETP, with ETP surviving the merger as a wholly owned subsidiary of Sunoco Logistics
MMcfmillion cubic feet
MTBEmethyl tertiary butyl ether

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NGANatural Gas Act of 1938
NGLnatural gas liquid, such as propane, butane and natural gasoline
NGPANatural Gas Policy Act of 1978
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
OSHAFederal Occupational Safety and Health Act
OTCover-the-counter
PanhandlePanhandle Eastern Pipe Line Company, LP and its subsidiaries
PCBspolychlorinated biphenyls
PennTexPennTex Midstream Partners, LP
PEPPermian Express Partners LLC
PEPLPanhandle Eastern Pipe Line Company, LP
PESPhiladelphia Energy Solutions
PHMSAPipeline Hazardous Materials Safety Administration
Phillips 66Phillips 66 Partners LP
Ranch JVRanch Westex JV LLC
RegencyRegency Energy Partners LP
Retail HoldingsETP Retail Holdings LLC, a subsidiary of ETP
RGSRegency Gas Services, a wholly-owned subsidiary of Regency
RIGSRegency Intrastate Gas System
RoverRover Pipeline LLC, a subsidiary of ETP
Sea RobinSea Robin Pipeline Company, LLC
SECSecurities and Exchange Commission
Southwest GasPan Gas Storage, LLC
Sunoco GPSunoco GP LLC, the general partner of Sunoco LP
Sunoco LogisticsSunoco Logistics Partners L.P.
Sunoco LPSunoco LP (previously named Susser Petroleum Partners, LP)
Sunoco PartnersSunoco Partners LLC, the general partner of Sunoco Logistics
SusserSusser Holdings Corporation
TCEQTexas Commission on Environmental Quality
TranswesternTranswestern Pipeline Company, LLC
TRRCTexas Railroad Commission
TrunklineTrunkline Gas Company, LLC, a subsidiary of Panhandle
USACUSA Compression Partners, LP
USAC HoldingsUSA Compression Holdings, LLC
WMBThe Williams Companies, Inc.
WTIWest Texas Intermediate Crude
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets,

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the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.


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PART I

ITEM 1. BUSINESS
Overview
We were formed in September 2002 and completed our initial public offering in February 2006. We areEnergy Transfer LP is a Delaware limited partnership with common units publicly traded on the NYSE under the ticker symbol “ETE.“ET.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE”“Energy Transfer” mean Energy Transfer Equity, L.P.LP and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References toUSAC.
The primary activities in which we are engaged, which are in the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.United States, and the operating subsidiaries through which we conduct those activities are as follows:
•natural gas operations, including the following:
•natural gas midstream and intrastate transportation and storage;
•interstate natural gas transportation and storage; and
•crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.
In 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 historical common units for ETP presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, discussed below.
The Parent Company’s principal sources of cash flow are derived from its direct and indirectaddition, we own investments in the limited partnerother businesses, including Sunoco LP and general partner interests in ETP and Sunoco LP,USAC, both of which are publicly traded master limited partnerships engagedpartnerships.
Energy Transfer derives cash flows from distributions related to its investment in diversified energy-related services,its subsidiaries, including Sunoco LP and USAC. The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the Partnership’s ownershipamount of Lake Charles LNG.
At January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
The Parent Company’savailable cash. Energy Transfer’s primary cash requirements are for distributions to its partners, general and administrative expenses and 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 Companyrequirements. Energy Transfer distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its unitholdersUnitholders 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 CompanyEnergy Transfer may issue debt or equity securities from time to time as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

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Index to Financial Statements
The following chart summarizes our organizational structure as of February 7, 2018.10, 2023. For simplicity, certain immaterial entities and ownership interests have not been depicted.


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Index to Financial Statements
Significant Achievements in 20172022
•In September, the Partnership completed the acquisition of Woodford Express, LLC, which owns a gas gathering and Beyondprocessing system in the SCOOP play of Southern Oklahoma.
•In August, the Partnership completed the sale of our interest in Energy Transfer Canada.
•In March, the Partnership purchased the membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas.
Segment Overview
See Note 16 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our segments.
Intrastate Transportation and Storage Segment
Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities, power generators and other third-party pipelines. Through our intrastate transportation and storage segment, we own and operate (through wholly-owned subsidiaries or through joint venture interests) approximately 11,600 miles of natural gas transportation pipelines with approximately 24 Bcf/d of transportation capacity, three natural gas storage facilities located in the state of Texas and two natural gas storage facilities located in the state of Oklahoma.
Energy Transfer operates one of the largest intrastate pipeline systems in the United States providing energy logistics to major trading hubs and industrial consumption areas throughout the United States. Our intrastate transportation and storage segment focuses on the transportation of natural gas to major markets from various prolific natural gas producing areas in Texas and Louisiana (Permian Basin and Barnett, Haynesville and Eagle Ford shales) through our Oasis Pipeline, our ETC Katy Pipeline, our RIGS pipeline, our natural gas pipeline and storage systems that are referred to as the ET Fuel System, and our HPL System. In addition, we operate EOIT in Oklahoma, delivering natural gas from various shale plays in the Anadarko and Arkoma Basins, as further described in “Asset Overview.”
Our intrastate transportation and storage segment’s results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay a fee even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.
We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies on our HPL System. Generally, we purchase natural gas from either the market (including purchases from our marketing operations) or from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and typically resold to customers based on an index price. In addition, our intrastate transportation and storage segment generates revenues from fees charged for storing customers’ working natural gas in our storage facilities and from managing natural gas for our own account.
We also own a 70% interest in Red Bluff Express Pipeline, which owns a pipeline in the Delaware Basin; and 16% membership interests in Comanche Trail Pipeline and Trans-Pecos Pipeline, both of which own pipelines delivering natural gas from the Waha Hub to the United States/Mexico border.
Interstate Transportation and Storage Segment
Natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users and other pipelines. Through our interstate transportation and storage segment, we directly own and operate approximately 19,945 miles of interstate natural gas pipelines with approximately 20.1 Bcf/d of transportation capacity and another approximately 7,085 miles and 12.2 Bcf/d of transportation capacity through joint venture interests.
Our vast interstate natural gas network spans the United States from Florida to California and Texas to Michigan, offering a comprehensive array of pipeline and storage services. Our pipelines have the capability to transport natural gas from nearly all Lower 48 onshore and offshore supply basins to customers in the Southeast, Gulf Coast, Southwest, Midwest, Northeast and Canada. Through numerous interconnections with other pipelines, our interstate systems can access virtually any supply or
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Index to Financial Statements
market in the country. As discussed further herein, our interstate segment operations are regulated by the FERC, which has broad regulatory authority over the business and operations of interstate natural gas pipelines.
Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Royal Dutch Shell plc (“Shell”).
Lake Charles LNG Export, our wholly-owned subsidiary, is developing a natural gas liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets.
Since the beginning of 2022, Lake Charles LNG Export has executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC. We have also signed nonbinding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the project. Upon completion of the LNG project, we expect to realize significant incremental cash flows from transportation of natural gas on our Trunkline pipeline system, and other Energy Transfer pipelines upstream from Lake Charles.
The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage services.
Midstream Segment
The midstream industry consists of natural gas gathering, compression, treating, processing, storage, and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells and transports it to larger pipelines for further transportation.
Treating plants remove carbon dioxide and hydrogen sulfide from natural gas that is higher in carbon dioxide, hydrogen sulfide or certain other contaminants, to ensure that it meets pipeline quality specifications. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream. Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas can be processed to take advantage of favorable margins for NGLs extracted from the gas stream.
Through our midstream segment, we own and operate natural gas gathering and NGL pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing capacity of approximately 11.7 Bcf/d. Our midstream segment focuses on the gathering, compression, treating, blending, and processing, and our operations are currently concentrated in major producing basins and shales in South Texas, West Texas, New Mexico, North Texas, East Texas, West Virginia, Pennsylvania, Ohio, Oklahoma, Arkansas, Kansas and Louisiana. Many of our midstream assets are integrated with our intrastate transportation and storage assets as well as our NGL assets.
Our midstream segment includes a 60% interest in Edwards Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities, and an oil pipeline and oil stabilization facility in South Texas; a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica Shale in Ohio; a 50% membership interest in Mi Vida JV LLC, which operates a cryogenic processing plant in West Texas; and a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
Our midstream segment results are derived primarily from margins we earn for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities.
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NGL and Refined Products Transportation and Services Segment
Our NGL and refined products operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic transactionsoff-take locations that provide access to multiple markets.
Our NGL and refined products transportation and services segment includes:
•approximately 5,650 miles of NGL pipelines;
•Nederland Terminal and connecting pipelines which provide transportation of ethane, propane, butane and natural gasoline from our Mont Belvieu Facility to our Nederland Terminal where these products can be exported;
•Marcus Hook Terminal which includes fractionation, storage and exporting assets. This facility is connected to our Mariner East Pipeline System, which provides for the transportation of ethane and LPG products from western Pennsylvania, West Virginia and eastern Ohio to our Marcus Hook Terminal where these component products can be exported, processed or locally distributed;
•NGL fractionation facilities with an aggregate capacity of 975 MBbls/d;
•NGL storage facility in 2017Mont Belvieu with a working storage capacity of approximately 58 MMBbls; and
•other NGL storage assets, located at our Cedar Bayou, Hattiesburg and Spindletop storage facilities, and our Nederland, Marcus Hook and Inkster NGL terminals with an aggregate storage capacity of approximately 25 MMBbls.
The NGL pipelines primarily transport NGLs from the Permian Basin and the Barnett and Eagle Ford Shales to Mont Belvieu, Texas, as well as NGLs from the Marcellus and Utica Shales to both our Marcus Hook Terminal and to customer facilities in Marysville, Michigan and to delivery points on the Canadian border.
NGL terminalling services are facilitated by approximately 10 MMBbls of NGL storage capacity. These operations also support our liquids blending activities, including the use of our patented butane blending technology. Refined products operations provide transportation and terminalling services through the use of approximately 3,670 miles of refined products pipelines and 37 active refined products marketing terminals. Our marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 MMBbls of refined products storage capacity. Our refined products operations utilize our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions throughout the United States. The mix of products delivered through our refined products pipelines varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. The products transported in these pipelines include multiple grades of gasoline and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Revenues in this segment are principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Fees are market-based, negotiated with customers and competitive with regional regulated pipelines and fractionators. Storage revenues are derived from base storage and throughput fees. This segment also derives revenues from fee-based export activities, the marketing of NGLs and processing and fractionating refinery off-gas.
Crude Oil Transportation and Services Segment
Our crude oil operations provide transportation (via pipeline and trucking), terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Through our crude oil transportation and services segment, we own and operate (through wholly-owned subsidiaries or joint venture interests) approximately 11,315 miles of crude oil trunk and gathering pipelines in the southwestern, northwestern and midwestern United States. This segment includes equity ownership interests in six crude oil pipeline systems, the Bakken Pipeline system, Bayou Bridge Pipeline, White Cliffs Pipeline, Maurepas Pipeline, the Permian Express pipelines and Enable South Central Pipeline. Our crude oil terminalling services operate with an aggregate storage capacity of approximately 66 MMBbls, including approximately 31 MMBbls at our Gulf Coast terminal in Nederland, Texas, approximately 18.2 MMBbls at our Gulf coast terminal on the Houston Ship Channel and approximately 7.6 MMBbls at our Cushing facility in Cushing, Oklahoma. Our crude oil acquisition and marketing activities utilize our pipeline and terminal assets, our proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the midcontinent United States.
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Revenues throughout our crude oil pipeline systems are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the FERC and other state regulatory agencies, as applicable.
Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil. Specifically, the crude oil acquisition and marketing activities include:
•purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
•storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
•buying and selling crude oil of different grades at different locations in order to maximize value;
•transporting crude oil using our pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and
•marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
Investment in Sunoco LP
Sunoco LP is engaged in the distribution of motor fuels to independent dealers, distributors, and other commercial customers and the distribution of motor fuels to end-user customers at retail sites operated by commission agents. Additionally, it receives rental income through the leasing or subleasing of real estate used in the retail distribution of motor fuel. Sunoco LP also operates 76 retail stores located in Hawaii and New Jersey.
Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.
Sunoco LP is the exclusive wholesale supplier of the Sunoco-branded and EcoMaxx-branded motor fuels, supplying an extensive distribution network of approximately 5,563 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest, South Central and Southeast regions of the United States and Puerto Rico. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.
Sunoco LP operations primarily consist of fuel distribution and marketing.
Investment in USAC
USAC provides natural gas compression services throughout the United States, including the Utica, Marcellus, Permian Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. USAC provides compression services to its customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, USAC’s compression services play a critical role in the production, processing and transportation of both natural gas and crude oil. As of December 31, 2022, USAC had 3.7 million horsepower in its fleet.
USAC operates a modern fleet of compression units, with an average age of approximately 11 years. USAC’s standard new-build compression units are generally configured for multiple compression stages allowing USAC to operate its units across a broad range of operating conditions. As part of USAC’s services, it engineers, designs, operates, services and repairs its compression units and maintains related support inventory and equipment.
USAC provides compression services to its customers under fixed-fee contracts with initial contract terms typically between six months to five years, depending on the application and location of the compression unit. USAC typically continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay a monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of its cash flows. USAC is not directly exposed to commodity price risk because it does not take title to the natural gas or crude oil involved in its services and because the natural gas used as fuel by its compression units is supplied by its customers without cost to USAC.
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USAC’s assets and operations are all located and conducted in the United States.
All Other Segment
Our “All Other” segment includes the following:
•Our gas marketing activities, which optimize basis pricing differentials by purchasing natural gas, transporting, primarily on company owned pipelines, and selling that gas primarily to industrial end-users or to other marketers.
•Our commodity marketing company, which focuses primarily on wholesale power trading activities.
•Our natural gas compression equipment business, which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
•Our wholly-owned subsidiary, Dual Drive Technologies, Ltd., which provides compression services to customers engaged in the transportation of natural gas, including our other segments.
•Our subsidiaries are involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities.
•In August 2022, we completed the sale of our 51% ownership interest in Energy Transfer Canada, which owns processing and gathering facilities in Alberta, Canada.
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Asset Overview
The following descriptions include summaries of significant assets within the Partnership’s reportable segments. Amounts, such as capacities, volumes and miles included in the following as discusseddescriptions are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.
The map below depicts the major assets of our core businesses, excluding the assets of Sunoco LP, USAC and the businesses in more detail herein:our all other segment. The map below and the maps included within the segment asset descriptions include certain non-wholly-owned joint ventures and exclude corporate and field offices and certain assets that are less significant to the Partnership on a consolidated basis.
Significant Achievements Related
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Intrastate Transportation and Storage
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The following details our pipelines and storage facilities in the intrastate transportation and storage segment:
Description of AssetsOwnership InterestMiles of Natural Gas PipelinePipeline Throughput Capacity
(Bcf/d)		Working Storage Capacity
(Bcf)
ET Fuel System100 %3,150 5.2 11.2 
Oasis Pipeline (1)
100 %750 2.0 — 
Houston Pipeline (“HPL”) System100 %3,920 5.3 52.5 
ETC Katy Pipeline100 %460 2.9 — 
Regency Intrastate Gas System (“RIGS”)100 %450 2.1 — 
Enable Oklahoma Intrastate Transmission (“EOIT”)100 %2,200 2.4 24.0 
Comanche Trail Pipeline16 %195 1.1 — 
Trans-Pecos Pipeline16 %140 1.4 — 
Red Bluff Express Pipeline70 %120 1.4 — 
(1)Includes bi-directional capabilities
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The following information describes our principal intrastate transportation and storage assets:
•The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipelines and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the three major natural gas trading centers in Texas: the Waha Hub near Pecos, Texas, the Maypearl Hub in Central Texas and the Carthage Hub in East Texas.
The ET Fuel System also includes our Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and our Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In January 2017, ETE issued 32.2 million common units representing limited partner interestsaddition, the ET Fuel System is integrated with our Godley processing plant which gives us the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from our gas gathering system known as the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
•The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.3 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with our gathering system known as the Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas gathered on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing us to bypass our processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
•The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Beaumont and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the Partnershipkey Houston Ship Channel and Katy Hub markets, allowing us to certain institutional investorsplay an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel, Carthage and Agua Dulce, as well as our Bammel storage facility.
The Bammel storage facility has a private transaction for gross proceedstotal working gas capacity of approximately $580 million,52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2022, we had approximately 17.2 Bcf committed under fee-based arrangements with third parties and approximately 32.8 Bcf stored in the facility for our own account.
•The ETC Katy Pipeline connects three treating facilities, one of which ETE usedwe own, with our gathering system known as Southeast Texas System. The ETC Katy pipeline serves producers in East and North Central Texas and provides access to purchase 23.7 million newly issued ETP common units.the Katy Hub. The ETC Katy pipeline expansions include the 36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL System.
In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds•RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets.
•EOIT is a 2,200-mile pipeline system that provides natural gas transportation and storage services to customers in Oklahoma. EOIT is a web-like configuration with multidirectional flow capabilities between numerous receipt points and delivery points. EOIT delivers natural gas from the offering were usedAnadarko and Arkoma Basins, including the SCOOP, STACK, Cana Woodford, Granite Wash, Cleveland, Tonkawa and Mississippi Lime Shale plays in western Oklahoma to repayutilities and industrial end users connected to EOIT and to interstate and intrastate pipelines interconnected with EOIT. EOIT also has two underground natural gas storage facilities in Oklahoma, which operate at a portioncombined capacity of 24 Bcf with a peak withdrawal rate of 0.60 Bcf/d.
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•Comanche Trail Pipeline is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.
•Trans-Pecos Pipeline is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
•The Red Bluff Express Pipeline is an approximately 120-mile intrastate pipeline that runs through the heart of the outstanding indebtedness under ETE’s term loan facilityDelaware Basin and for general partnership purposes.
Significant Achievements Relatedconnects our Orla Plant, as well as third-party plants to ETP
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectlythe Waha Oasis Header. The Partnership owns a 100%70% membership interest sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC,and operates Red Bluff Express.
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Index to MarEn Bakken Company LLC, an entity jointly owned by MPLX LPFinancial Statements
Interstate Transportation and Enbridge Energy Partners, L.P., for $2.00 billionStorage
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The following details our pipelines in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interestthe interstate transportation and storage segment:
Description of AssetsOwnership InterestMiles of Natural Gas PipelinePipeline Throughput Capacity
(Bcf/d)		Working Storage Capacity
(Bcf)
Florida Gas Transmission (“FGT”)50 %5,380 3.9 — 
Transwestern Pipeline100 %2,590 2.1 — 
Panhandle Eastern Pipe Line (1)
100 %6,300 2.8 73.0 
Trunkline100 %2,190 0.9 13.0 
Tiger100 %200 2.4 — 
Fayetteville Express Pipeline50 %185 2.0 — 
Sea Robin Pipeline100 %740 2.0 — 
Stingray Pipeline100 %290 0.4 — 
Rover Pipeline32.6 %720 3.4 — 
Midcontinent Express Pipeline50 %510 1.8 — 
Enable Gas Transmission (“EGT”)100 %5,700 4.8 29.3 
Mississippi River Transmission (“MRT”)100 %1,600 1.7 48.9 
Southeast Supply Header (“SESH”)50 %290 1.1 — 
Gulf Run Pipeline100 %
335(2)
3.0(2)
— 
(1)Storage capacity figure includes storage leased from Southwest Gas and third-party companies.
(2)Includes the newly constructed 135-mile pipeline and approximately 200 miles of pipeline acquired from EGT.
The following information describes our principal interstate transportation and storage assets:
•FGT extends from South Texas through the Gulf Coast region of the United States to south Florida. FGT is the principal transporter of natural gas to the Florida energy market, delivering approximately 60% of the natural gas consumed in eachthe
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Index to Financial Statements
state. In addition, FGT’s numerous intrastate and ETCO. The remaining 25% of each of Dakota Accessinterstate pipeline interconnections with major interstate and ETCOintrastate natural gas pipelines provide access to diverse natural gas supply sources. FGT’s customers include electric utilities, independent power producers, industrial end-users and local distribution companies. FGT is owned by wholly-owned subsidiaries of Phillips 66. As discussed below, in July 2017, ETP contributedCitrus, a portion of its ownership interest in Dakota Access and ETCO to PEP. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

In February 2017, Sunoco Logistics formed PEP, a strategic50/50 joint venture with ExxonMobil.Kinder Morgan, Inc.
•Transwestern Pipeline transports natural gas supply from the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma panhandles. The system has bi-directional capabilities and can access Texas and Midcontinent natural gas market hubs, as well as major western markets in Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
•Panhandle Eastern Pipe Line’s transmission system consists of four large diameter mainline pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle contracts for over 73 Bcf of natural gas storage.
•Trunkline’s transmission system consists of one large diameter mainline pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan. Trunkline has one natural gas storage field located in Louisiana.
•Tiger is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.
•Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route. Fayetteville Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc.
•Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico.
•Stingray Pipeline is an interstate natural gas pipeline system with assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana.
•Rover Pipeline is a large diameter pipeline which transports natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States, as well as to Ontario, Canada.
•Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline system in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc., the operator of the system.
•EGT provides natural gas transportation and storage services to customers in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas. EGT has two underground storage facilities in Oklahoma and one underground natural gas storage facility in Louisiana. Through numerous pipeline interconnections along the system and at the Perryville Hub, EGT customers have access to the Midwest and Northeast markets, as well as most of the major natural gas consuming markets east of the Mississippi River.
•MRT provides natural gas transportation and storage services in Texas, Arkansas, Louisiana, Missouri and Illinois. MRT has underground natural gas storage facilities in Louisiana and Illinois. MRT receives natural gas from a variety of interstate and intrastate pipelines through its interconnections and delivers natural gas primarily to the St. Louis market.
•SESH, a 50/50 joint venture with Enbridge Inc., provides transportation services in Louisiana, Mississippi and Alabama. SESH transports natural gas from the Perryville Hub in Louisiana to its endpoint in Mobile County, Alabama. SESH has interconnections with third party natural gas pipelines and provides access to major Southeast and Northeast markets and transports directly to generating facilities in Mississippi and Alabama and to interconnecting pipelines that supply companies generating electricity for the Florida power market.
•Gulf Run Pipeline, placed in service in December 2022, is a large diameter pipeline that runs from the heart of the Haynesville Shale in East Texas and North Louisiana to the Carthage and Perryville natural gas hubs and other key markets along the Gulf Coast.
Regasification Facility
Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d.
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Liquefaction Project
Lake Charles LNG Export, our wholly-owned subsidiary, is developing a natural gas liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets.
Since the beginning of 2022, Lake Charles LNG Export has executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC. We have also signed nonbinding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the project. Upon completion of the LNG project, we expect to realize significant incremental cash flows from transportation of natural gas on our Trunkline pipeline system, and other Energy Transfer pipelines upstream from Lake Charles.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to Lake Charles LNG Export. In March 2013, Lake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, Lake Charles LNG Export 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”). In October 2020, the DOE extended the FTA Authorization and Non-FTA Authorization to 30- and 25-year terms, respectively, following first deliveries on or before December 2025, consistent with the FERC authorization for the project. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively, commencing with the completion of construction of the liquefaction facility. In addition, Lake Charles LNG Export received its wetlands permits from the 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.
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Midstream
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The following details our assets in the midstream segment:
Description of AssetsNet Gas Processing Capacity
(MMcf/d)
South Texas2,430 
Ark-La-Tex1,990 
North Central Texas700 
Permian2,815 
Midcontinent3,585 
Eastern200 
The following information describes our principal midstream assets:
South Texas Region:
•Our South Texas assets, which include the Southeast Texas System and the Eagle Ford System, are an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford Shale.
The assets in our Southeast Texas System include a large natural gas gathering system that covers thirteen counties between Austin and Houston, Texas and connects to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. This system also includes three natural gas processing plants (La Grange, Alamo and Brookeland) with an aggregate capacity of 510 MMcf/d. These plants process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines.
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Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The assets in our Eagle Ford System consist of 30-inch and 42-inch natural gas gathering pipelines originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. These assets also include four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with an aggregate capacity of 1.9 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines.
•We own a 60% interest in Edward Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities, and an oil pipeline and oil stabilization facility in South Texas.
Ark-La-Tex Region:
•Our Ark-La-Tex assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, Tristate, Logansport, Magnolia, Olympia, Amoruso, and Lumberjack systems, which collectively include eleven natural gas treating facilities, with aggregate capacity of 3.0 Bcf/d.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that connects to a third party that provides access to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the fourteen natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Lincoln, Rosewood, Mt. Olive, Panola, Sligo and Waskom) have an aggregate capacity of 2.0 Bcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
•The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley plant, which processes rich gas produced from the Barnett Shale and STACK play, with an aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
•The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the midcontinent region of the United States and Texas natural gas markets. The NGL market outlets includes our NGL pipeline system. The Permian Basin Gathering System includes twelve processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keystone, Tippet, Orla, Panther, Rebel, Grey Wolf and Arrowhead) with an aggregate processing capacity of 2.6 Bcf/d and one natural gas conditioning facility with an aggregate capacity of 200 MMcf/d.
•We own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of the joint venture.
•The Partnership previously owned a 50% membership interest in Ranch Westex JV LLC, which was sold in 2022.
Midcontinent Region:
•The Midcontinent Systems are located in three large natural gas producing regions in the United States: the Hugoton Basin in southwest Kansas, the Anadarko Basin in the Texas Panhandle and Oklahoma, including the STACK and SCOOP plays, and the Arkoma Basin in Eastern Oklahoma and Arkansas. These mature basins have continued to provide generally long-lived, predictable production volumes. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include 24 natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Hamlin, Spearman, Crescent, Rose Valley, Hopeton, Bradley, Bradley II, McClure, Wheeler, South Canadian, Clinton, Roger Mills, Canute, Cox City, Thomas, Calumet and Wetumka) with an aggregate capacity of approximately 3.1 Bcf/d.
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•We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
•We own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
•We own a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
•In September 2022, we acquired Woodford Express, LLC, which has cryogenic gas processing and treatment capacity of 450 MMcf/d and over 200 miles of gathering lines that are connected to Energy Transfer’s pipeline network.
Eastern Region:
•The Eastern Region assets are located in eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica Shales. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipelines, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.
•We also own a 51% membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
•We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, and which delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.
NGL and Refined Products Transportation and Services
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The following details the assets in our NGL and refined products transportation and services segment:
Description of AssetsMiles of Liquids PipelineNGL Fractionation / Processing Capacity
(MBbls/d)		Working Storage Capacity
(MBbls)
Liquids Pipelines:
Gulf Coast NGL Express900 — — 
West Texas Gateway510 — — 
Other Permian Basin NGL1,600 — — 
Mariner East680 — — 
Mariner West450 — — 
Mont Belvieu to Nederland270 
White Cliffs(1)
540 — — 
Other NGL600 — — 
Liquids Fractionation and Storage Facilities:
Mont Belvieu— 940 58,000 
Spindletop— — 8,000 
ET Geismar Olefins(2)
100 35 — 
Hattiesburg— — 5,200 
Cedar Bayou— — 1,600 
NGL Terminals:
Nederland— — 1,900 
Orbit Gulf Coast— — 1,200 
Marcus Hook— — 6,000 
Inkster— — 860 
Refined Products Pipelines:
Eastern region1,580 — — 
Midcontinent region440 — — 
Southwest region550 — — 
Inland600 — — 
JC Nolan Pipeline500 — — 
Refined Products Terminals:
Eagle Point— — 6,700 
Marcus Hook Terminal— — 930 
Marcus Hook Tank Farm— — 1,900 
Marketing Terminals— — 7,700 
JC Nolan Terminal— — 130 
(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
(2)Additionally, the ET Geismar Olefins off-gas processing facility has inlet volume capacity of 54 MMcf/d.
The following information describes our principal NGL and refined products transportation and services assets:
•Gulf Coast NGL Express is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelines, with throughput capacity of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
•West Texas Gateway transports mixed NGLs produced in the Permian Basin and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.
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•The Mariner East Pipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports NGLs from the Marcellus and Utica Shales in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets.
•The Mont Belvieu to Nederland Pipeline System consists of three pipelines and delivers export-grade propane, butane and natural gasoline from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a total throughput capacity of approximately 530 MBbls/d. In addition, it includes an export-grade ethane pipeline utilized for our Orbit Gulf Coast joint venture as described below.
•The Mariner West pipeline provides transportation of ethane from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d.
•The White Cliffs NGL pipeline, in which we have 51% ownership interest, transports mixed NGLs produced in the DJ Basin to Cushing, Oklahoma where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90 MBbls/d.
•Other NGL pipelines include the 127-mile Justice pipeline, the 45-mile Freedom pipeline, the 20-mile Spirit pipeline and a 50% interest in the 87 mile Liberty pipeline.
•Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 58 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators. We have an additional 8 MMBbls of salt dome capacity at our Spindletop facility which we acquired in March 2022, and is located in Beaumont, Texas.
•Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Gulf Coast NGL Express, West Texas Gateway and Justice pipelines.
•ET Geismar Olefins consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
•The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-based cash flows.
•The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.
•The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs in connection with the Mont Belvieu to Nederland Pipeline System, which provides transportation of propane, butane and natural gasoline products from our Mont Belvieu, Texas storage and fractionation complex to the Nederland Terminal, where such products can be exported via ship.
•The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 200 MBbls/d, delivering from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas, as well as a 180 MBbls/d ethane refrigeration facility and 1.2 MMBbls of storage capacity.
•The Marcus Hook Terminal includes fractionation, terminalling and storage assets, with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground NGL refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Terminal currently serves as an off-take outlet for our Mariner East Pipeline System.
The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.
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•The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use the Inkster terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
•The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product pipelines in eastern, central and north central Pennsylvania, 8-inch refined products pipeline in western New York and various diameter refined products pipelines in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
•The midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan.
•The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products pipeline.
•The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio.
•The JC Nolan Pipeline, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco Logistics contributedLP, transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 36 MBbls/d.
•We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.
•In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•The JC Nolan Terminal, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, provides diesel fuel storage in Midland, Texas.
•This segment also includes the following joint ventures: a 15% membership interest in Explorer, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur and Houston, Texas and extends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.
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Crude Oil Transportation and Services
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The following details our pipelines and terminals in its crude oil transportation and services operations:
Description of AssetsOwnership InterestMiles of Crude PipelineWorking Storage Capacity
(MBbls)
Dakota Access Pipeline36.40 %1,170 — 
Energy Transfer Crude Oil Pipeline36.40 %745 — 
Bayou Bridge Pipeline60 %210 — 
Permian Express Pipelines87.7 %1,760 — 
Wattenberg Oil Trunkline100 %75 360 
White Cliffs Pipeline(1)
51 %530 100 
Maurepas Pipeline51 %35 — 
Other Crude Oil Pipelines100 %6,790 — 
Nederland Terminal100 %— 31,000 
Fort Mifflin Terminal100 %— 3,300 
Eagle Point Terminal100 %— 1,800 
Midland Terminal100 %— 1,000 
Marcus Hook Terminal100 %— 1,000 
Houston Terminal100 %— 18,200 
Cushing Terminal100 %— 7,600 
Patoka, Illinois Terminal87.7 %— 1,900 
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(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:
Crude Oil Pipelines
Our crude oil pipelines consist of approximately 11,315 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including our wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, Mid-Valley and Wattenberg Oil Trunkline. Additionally, we have equity ownership interests in six crude oil pipelines. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
•Bakken Pipeline. TheDakota Access Pipeline and Energy Transfer Crude Oil Pipeline are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915-mile pipeline that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas. The Bakken Pipeline has a capacity of up to 750 MBbls/d. The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
The Dakota Access Pipeline consists of approximately 1,170 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.
The Energy Transfer Crude Oil Pipeline consists of approximately 675 miles of mostly 30-inch converted natural gas pipeline and 70 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
•Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between Energy Transfer and a subsidiary of Phillips 66, in which we have a 60% ownership interest and serve as the operator of the pipeline. Phase I of the pipeline is a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, and Phase II of the pipeline, is a 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana.Bayou Bridge Pipeline has a capacity of approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
•Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview, and Louisiana Access, pipelines. ExxonMobil contributed its Longview to Louisiana and PegasusNederland Access pipelines. These pipelines Hawkinsare comprised of crude oil trunk pipelines and crude oil gathering system, an idle pipelinepipelines in southernTexas and Oklahoma and its Patoka, Illinois terminal. Assets contributedprovide takeaway capacity from the Permian Basin, with origins in multiple locations in West Texas.
•White Cliffs Crude Pipeline. White Cliffs Pipeline owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to PEP by ExxonMobil were reflected at fair value onCushing, Oklahoma.
•Maurepas Pipeline. The Maurepas Pipeline consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Partnership’s consolidated balance sheet atGulf Coast region.
•Other Crude Oil pipelines include the dateMid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.Midwest United States.
In April 2017, Energy Transfer Partners, L.P.addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”)truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which Sunoco Logistics acquired Energy Transfer Partners, L.P.supplies Marathon Petroleum Corporation’s refinery in a unit-for-unit transaction, withDetroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma and Kansas. We have the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCOability to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator ofdeliver substantially all of the assets. As such, PEPcrude oil gathered on our Oklahoma and Kansas systems to Cushing, Oklahoma. We are one of the
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largest purchasers of crude oil from producers in the area and our crude oil acquisition and marketing activities business is reflected asthe primary shipper on our Oklahoma crude oil system.
We also own crude oil and condensate gathering assets in the Anadarko Basin and the Williston Basin. The Anadarko Basin assets were designed and built to serve the crude oil and condensate production in the SCOOP and STACK plays. A portion of these operations are conducted through Enable South Central Pipeline, a consolidatedjoint venture with a subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest,CVR Energy, Inc., which is reflectedoperated by us and in “Capital contributionswhich we own a 60% membership interest. The Williston Basin crude oil and produced water gathering assets were designed and built to receive crude oil on pipelines near our customers’ wells for delivery to third-party transportation pipelines, and produced water gathering pipelines for delivery to third-party disposal wells.
Crude Oil Terminals
•Nederland. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately 31 MMBbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland Terminal can receive crude oil at three of its six ship docks and three of its four barge berths. The three ship docks are capable of receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls. The terminal also has crude oil rail unloading facilities, including steam availability for heating heavy oils prior to loading.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 MMBbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
•Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from noncontrolling interest”marine vessels on the Delaware River.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks. The Darby Creek tank farm is a primary crude oil storage terminal that receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines and has a total storage capacity of approximately 2.7 MMBbls.
•Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the consolidated statementDelaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of equity.approximately 1.8 MMBbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
In October 2017, ETP completed•Midland. The Midland terminal is located in Midland, Texas and includes approximately 1 MMBbls of crude oil storage, a combined 20 lanes of truck loading and unloading, and provides access to the previously announced contribution transactionPermian Express 2 pipeline.
•Marcus Hook. The Marcus Hook Terminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 MMBbls.
•Patoka, Illinois. The Patoka, Illinois terminal is a tank farm owned by the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 1.9 MMBbls of crude oil storage.
•Houston. The Houston Terminal consists of storage tanks located on the Houston Ship Channel with a fund managed by Blackstone Energy Partnersan aggregate storage capacity of 18.2 MMBbls used to store, blend and Blackstone Capital Partners, pursuanttransport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.
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•Cushing. The Cushing Terminal has approximately 7.6 MMBbls of crude oil storage, of which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP5.6 MMBbls are leased to customers and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP2.0 MMBbls are available for its pro rata share of the Rover construction costs incurred by ETP through the closing date, alongcrude oil operations, blending and marketing activities. The storage terminal has inbound connections with the payment of additional amounts subject to certain adjustments.
In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”)White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which ETP will contribute to USAC 100% of the membership interests of CDM and CDM E&T for aggregate consideration of $1.7 billion, consisting of USAC common units, new USAC Class B units and cash. The Class B units will be substantially similar to USAC common units, except the Class B units will not receive distributions paid with respect to USAC common units prior to the one year anniversary of the closing date of the CDM Contribution Agreement. Each Class B Unit will convert into one USAC common unit on such one year anniversary. In connection with the foregoing, ETP entered into a purchase agreement with ETE, ETP LLC, USAC Holdings and, for certain limited purposes, R/C IV USACP Holdings, L.P., pursuant to which ETE and ETP LLC will acquire from USAC Holdings (i) all of the outstanding interestsother major storage terminals in the general partner of USACCushing. The Cushing terminal also includes truck unloading facilities.
Crude Oil Acquisition and (ii) 12,466,912 USAC common units for $250 millionMarketing
Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 363 crude oil transport trucks, 350 trailers and approximately 166 crude oil truck unloading facilities, as well as third-party truck, rail, pipeline and marine assets.
Investment in cash. The transactions are expected to close in the first half of 2018, subject to customary closing conditions.
Significant Achievements Related to Sunoco LP
On January 18, 2017, withSunoco LP’s fuel distribution and marketing operations are conducted by the assistancefollowing consolidated subsidiaries:
•    Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in more than 40 states and territories throughout the East Coast, Midwest, South Central and Southeast regions of a third-party brokerage firm,the United States. Sunoco LP launched a portfolio optimization plan to marketLLC also processes transmix and sell 97 real estate assets. Real estate assets includeddistributes refined product through its terminals in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located inAlabama, Arkansas, Florida, Louisiana, Massachusetts, Michigan, New Hampshire,Indiana, Illinois, Maryland, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed throughVirginia;
•    Sunoco Retail LLC (formerly Sunoco Property Company LLC) (“Sunoco Retail”), a sealed-bid sale. Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey and distributes motor fuel in Puerto Rico. Sunoco Retail also leases owned sites to commissioned agents who sell motor fuels to the motoring public on Sunoco Retail’s behalf for a commission;
•    Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands; and
•Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands and leases owned sites to commission agents who sell motor fuels on Aloha’s behalf for a commission.
Sunoco LP will review all bids before divesting any assets. purchases motor fuel primarily from independent refiners and major oil companies and distributes it throughout the East Coast, Midwest, South Central and Southeast regions of the United States, as well as Hawaii to:
•76 company owned and operated retail stores;
•504 independently operated commission agent locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;
•6,897 retail stores operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and
•approximately 1,800 other commercial customers, including unbranded retail stores, other fuel distributors, school districts and municipalities and other industrial customers.
Sunoco LP’s operations also include retail operations in Hawaii and New Jersey, credit card services and franchise royalties.
Investment in USAC
The following details the assets of USAC:
USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 87.1% of its total fleet horsepower as of December 31, 2022. The remainder of its fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.
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The following table provides a summary of USAC’s compression units by horsepower as of December 31, 2022:
Unit HorsepowerFleet HorsepowerNumber of UnitsHorsepower on Order (1)Number of Units on OrderTotal HorsepowerNumber of UnitsPercent of Fleet HorsepowerPercent of Units
Small horsepower
<400502,012 2,956 — — 502,012 2,956 12.9 %54.2 %
Large horsepower
>400 and <1,000428,947 732 — — 428,947 732 11.1 %13.4 %
>1,0002,785,895 1,698 165,000 66 2,950,895 1,764 76.0 %32.4 %
Total large horsepower3,214,842 2,430 165,000 66 3,379,842 2,496 87.1 %45.8 %
Total horsepower3,716,854 5,386 165,000 66 3,881,854 5,452 100.0 %100.0 %
(1)As of December 31, 2017,2022, USAC had 66 large horsepower units, consisting of 165,000 horsepower, on order for delivery during 2023.
All Other
The following details the 97significant assets in the “All Other” segment.
Compression
We own Dual Drive Technologies, Ltd, which provides compression services to customers engaged in the transportation of natural gas, including our other segments.
Natural Resources Operations
Our Natural Resources operations primarily involve the management and leasing of coal properties 40 have been sold, 5 are under contractand the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to be sold,certain lessees and 11 continue to be marketed byend-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2022, we owned or controlled approximately 733 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the third-party brokerage firm. Additionally, 32 were sold to 7-ElevenIllinois Basin, properties in southern Illinois, Indiana, and nine are partwestern Kentucky and as the operator of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.end-user coal handling facilities.
On March 30, 2017, the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.
Canadian Operations
In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.
On January 23, 2018, Sunoco LPAugust 2022, we completed the sale of a portfolio of approximately 1,030 Sunoco LP operated retail fuel outletsour 51% ownership interest in 19 geographic regions, together with ancillary businessesEnergy Transfer Canada, which owns processing and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”).gathering facilities in Alberta, Canada.

Business Strategy
Our primary business objective is to increase cash available for distributions to our unitholders by actively assisting our subsidiaries in executing their business strategies by assisting in identifying, evaluating and pursuing strategic acquisitions and growth opportunities. In general, we expect that we will allow our subsidiaries the first opportunity to pursue any acquisition or internal growth project that may be presented to us which may be within the scope of their operations or business strategies. In the future, we may also support the growth of our subsidiaries through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to our subsidiaries. This funding could be used for the acquisition by one of our subsidiaries of a business or asset or for an internal growth project. In addition, the availability of this capital could assist our subsidiaries in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.
Segment Overview
Our reportable segments are as follows:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP including
Sunoco LP’s fuel distribution and marketing operations are conducted by the following consolidated operations ofsubsidiaries:
•    Sunoco, LP;
InvestmentLLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in Lake Charles LNG, includingmore than 40 states and territories throughout the operations of Lake Charles LNG;East Coast, Midwest, South Central and
Corporate and Other, including the activities Southeast regions of the Parent Company.United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama, Arkansas, Florida, Indiana, Illinois, Maryland, New Jersey, New York, Texas and Virginia;
The businesses within these segments are described below. See Note 15 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our reportable segments.
Investment in ETP
ETP’s operations include the following:
Intrastate Transportation and Storage Operations
ETP’s natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through its intrastate transportation and storage operations, ETP•    Sunoco Retail LLC (formerly Sunoco Property Company LLC) (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates approximately 7,900 miles of natural gas transportation pipelines with approximately 15.2 Bcf/d of transportation capacityretail stores that sell motor fuel and three natural gas storage facilities locatedmerchandise primarily in the state of Texas. ETPNew Jersey and distributes motor fuel in Puerto Rico. Sunoco Retail also owns a 49.99% general partner interest in RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisianaleases owned sites to downstream pipelines and markets. ETP owns a 16% membership interest in the Trans-Pecos and Comanche Trail pipelines, a 338-mile intrastate pipeline system that delivers natural gas from the Waha Hub near Midland, Texascommissioned agents who sell motor fuels to the United States/Mexico border.motoring public on Sunoco Retail’s behalf for a commission;
Through ETC OLP, ETP owns the largest intrastate pipeline system in the United States with interconnects to Texas markets•    Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and to major consumption areas throughout the United States. ETP’s intrastate transportation and storage operations focusoperates terminal facilities 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 pipelineHawaiian Islands; 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)•Aloha Petroleum, Ltd. (“Aloha”), 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.
Interstate Transportation and Storage Operations
ETP’s natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through its

interstate transportation and storage operations, ETP directlyHawaii corporation, owns and operates approximately 11,800 milesretail stores on the Hawaiian Islands and leases owned sites to commission agents who sell motor fuels on Aloha’s behalf for a commission.
Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes it throughout the East Coast, Midwest, South Central and Southeast regions of interstate natural gas pipelines with approximately 10.3 Bcf/d of transportation capacity and has a 50% interest in the joint venture that owns the 185-mile Fayetteville Express pipeline and the 500-mile Midcontinent Express pipeline. ETP also owns a 50% interest in Citrus, which owns 100% of FGT, an approximately 5,360 mile pipeline system that extends from South Texas through the Gulf Coast to south Florida. ETP operates the FEP and FGT joint ventures.
ETP’s interstate transportation and storage operations include Panhandle, which owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the 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.
The Rover Pipeline is a new 713-mile natural gas pipeline designed to transport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States, as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market. CurrentlyHawaii to:
•76 company owned and operated retail stores;
•504 independently operated commission agent locations where Sunoco LP sells motor fuel to customers under construction, portions of the pipeline are in service transporting gas from processing plants in Eastern Ohio for delivery to other pipeline interconnects in Eastern Ohio as well as the Midwest Hub near Defiance, Ohio, where the gas will be delivered for distribution to markets across the United States. The Rover Pipeline Phase 1A and 1B are in servicecommission agent arrangements with a capacity of approximately 1.7 Bcf/d.such operators;
ETP also owns a 50% interest in the MEP pipeline system, which is•6,897 retail stores operated by KMI,independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; 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•approximately 1,800 other commercial customers, including unbranded retail stores, other fuel distributors, school districts and termsmunicipalities 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.other industrial customers.
The results from ETP’s interstate transportation and storage operations are primarily derived from the fees ETP earns from natural gas transportation and storage services.
Midstream Operations
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing, storage and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells 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 its intrastate transportation and storage assets.
ETP’s midstreamSunoco LP’s operations also include a 60% interestretail operations in ELG, which operates natural gas gathering, oil pipeline,Hawaii and oil stabilization facilitiesNew Jersey, credit card services and franchise royalties.
Investment 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.USAC
The resultsfollowing details the assets of USAC:
USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from ETP’s midstream operations401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 87.1% of its total fleet horsepower as of December 31, 2022. The remainder of its fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily derived from margins ETP earns for naturalused in 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.lift applications.
NGL and Refined Products Transportation and Services Operations
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ETP’s NGL operations transport, store and execute acquisition and marketing activities utilizingIndex to Financial Statements
The following table provides a complementary networksummary of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets.USAC’s compression units by horsepower as of December 31, 2022:
Liquids 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.
Unit HorsepowerFleet HorsepowerNumber of UnitsHorsepower on Order (1)Number of Units on OrderTotal HorsepowerNumber of UnitsPercent of Fleet HorsepowerPercent of Units
Small horsepower
<400502,012 2,956 — — 502,012 2,956 12.9 %54.2 %
Large horsepower
>400 and <1,000428,947 732 — — 428,947 732 11.1 %13.4 %
>1,0002,785,895 1,698 165,000 66 2,950,895 1,764 76.0 %32.4 %
Total large horsepower3,214,842 2,430 165,000 66 3,379,842 2,496 87.1 %45.8 %
Total horsepower3,716,854 5,386 165,000 66 3,881,854 5,452 100.0 %100.0 %
ETP’s NGL and refined products transportation and services operations include approximately 4,300 miles of NGL pipelines, five NGL and propane fractionation facilities with an aggregate capacity of 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 the segment has 3 million Bbls of salt dome storage capacity near Hattiesburg, Mississippi. ETP is currently constructing a fifth and sixth fractionator in Mont Belvieu, Texas, which are expected to be operational in the third quarter of 2018 and the second quarter of 2019, respectively. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu.
Terminalling services are facilitated by approximately 7 million Bbls of NGLs storage capacity, including approximately 1 million Bbls of storage at ETP’s Nederland, Texas terminal facility, 1 million Bbls of storage at our Inkster, Michigan terminal facility and 5 million Bbls at ETP’s Marcus Hook, Pennsylvania terminal facility (the “Marcus Hook Industrial Complex”). These operations also support ETP’s NGLs blending activities, including the use of ETP’s patented butane blending technology.
Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and 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.
This segment also includes revenues earned from the marketing of NGLs and processing and fractionating refinery off-gas. Marketing of NGLs primarily generates margin from selling ratable NGLs to end users and from optimizing storage assets.

Processing and fractionation of refinery off-gas margin is generated from a percentage-of-proceeds of O-grade product sales and income sharing contracts, which are subject to market pricing of olefins and NGLs.
ETP’s refined products operations provide transportation and terminalling services, through the use of approximately 2,200 miles of refined products pipelines and approximately 40 active refined products marketing terminals. ETP’s marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 million Bbls of refined products storage capacity. ETP’s refined products operations include its Eagle Point facility in New Jersey, which has approximately 6 million Bbls of refined products storage capacity. The operations also include ETP’s equity ownership interests in four refined products pipeline companies. The operations also perform terminalling activities at ETP’s Marcus Hook Industrial Complex. ETP’s refined products operations utilize its integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions in the United States.
Crude Oil Transportation and Services Operations
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 the operations are approximately 9,360 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States and equity ownership interests in two crude oil pipelines. ETP’s crude oil terminalling services operate with an aggregate storage capacity of approximately 33 million Bbls, including approximately 26 million Bbls at ETP’s Gulf Coast terminal in Nederland, Texas and approximately 3 million Bbls at ETP’s Fort Mifflin terminal complex in Pennsylvania. ETP’s crude oil 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.
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 other state regulatory agencies, as applicable.
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. Specifically, the crude oil acquisition and marketing activities include:
purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
buying and selling crude oil of different grades, at different locations in order to maximize value;
transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and
marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
In November 2016, ETP purchased a crude oil acquisition and marketing business from Vitol, with operations based in the Permian Basin, Texas. Included in the acquisition was a significant acreage dedication from an investment-grade Permian producer.
ETP’s Other Operations and Investments
ETP’s other operations and investments include the following:
ETP owns an equity method investment in limited partner units of Sunoco LP. (1)As of December 31, 2017, ETP’s investment consisted2022, USAC had 66 large horsepower units, consisting of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units165,000 horsepower, on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.order for delivery during 2023.
ETP’s wholly-owned subsidiary, Sunoco, Inc., owns an approximate 33% non-operating interest in PES, a refining joint venture with All Other
The Carlyle Group, L.P., which owns a refinery in Philadelphia.
PES Holdings, LLC ("PES Holdings") and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018following details the significant assets in the United States Bankruptcy Court for the District of Delaware to implement a prepackaged reorganization plan that will allow its shareholders to retain a minority stake. PES Holdings' Chapter 11 Plan (“Plan”) proposes to inject $260 million in new capital into PES Holdings, cut debt service obligations by about $35 million per year and remove debt maturities before 2022.  Under that Plan, PES Holdings’ non-debtor parent, PES, in“All Other” segment.
Compression
We own Dual Drive Technologies, Ltd, which ETP holds an indirect 33% equity interest, will provide a $65 million cash contribution in exchange for a 25% stake in the reorganized debtor. After the restructuring, the proportionate ownership of Carlyle Group, L.P. and ETP in PES Holdings will be 16.26% and 8.13%, respectively. Finally,

Sunoco Logistics Partners Operations L.P. (“SXL Operating Partnership”), a subsidiary of ETP, is providing an additional $75 million exit loan ranked pari passu with the other debt.  SXL Operating Partnership’s, PES Holdings’ and ETP’s current contracts will be assumed, without any impairments, in the Chapter 11, and business operations will continue uninterrupted.  The financial reorganization is expected to complete in the first quarter of 2018.
ETP conducts marketing operations in which it markets the natural gas that flows through its gathering and intrastate transportation assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other suppliers and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, ETP purchases gas or acts as an agent for small independent producers that may not have marketing operations.
ETP owns a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’sour other operations.segments.
ETP owns a 40% interest in the parent of LCL, which is developing a LNG liquefaction project.Natural Resources Operations
ETP owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. ETP also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. These assets areOur Natural Resources operations primarily owned through CDM and CDM E&T. As discussed in “Recent Developments” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in January 2018, ETP entered into an agreement to contribute these assets to USAC.
ETP is involved ininvolve the management and leasing of coal and natural resources properties and the relatedsubsequent collection of royalties. ETPWe also earnsearn 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. These operations also includeroyalties and from coal transportation, or wheelage fees. As of December 31, 2022, we owned or controlled approximately 733 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
ETP alsoCanadian Operations
In August 2022, we completed the sale of our 51% ownership interest in Energy Transfer Canada, which owns PEI Power Corp.processing and PEI Power II, which own and operate a facilitygathering facilities in Pennsylvania that generates a total of 75 megawatts of electrical power.Alberta, Canada.
Investment in Sunoco LPInterstate Transportation and Storage
Sunoco LP is engagedet-20221231_g5.jpg
The following details our pipelines in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers,interstate transportation and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites.storage segment:
Wholesale Operations
Description of AssetsOwnership InterestMiles of Natural Gas PipelinePipeline Throughput Capacity
(Bcf/d)		Working Storage Capacity
(Bcf)
Florida Gas Transmission (“FGT”)50 %5,380 3.9 — 
Transwestern Pipeline100 %2,590 2.1 — 
Panhandle Eastern Pipe Line (1)
100 %6,300 2.8 73.0 
Trunkline100 %2,190 0.9 13.0 
Tiger100 %200 2.4 — 
Fayetteville Express Pipeline50 %185 2.0 — 
Sea Robin Pipeline100 %740 2.0 — 
Stingray Pipeline100 %290 0.4 — 
Rover Pipeline32.6 %720 3.4 — 
Midcontinent Express Pipeline50 %510 1.8 — 
Enable Gas Transmission (“EGT”)100 %5,700 4.8 29.3 
Mississippi River Transmission (“MRT”)100 %1,600 1.7 48.9 
Southeast Supply Header (“SESH”)50 %290 1.1 — 
Gulf Run Pipeline100 %
335(2)
3.0(2)
— 
Sunoco LP is a wholesale distributor of motor fuels and other petroleum products which Sunoco LP supplies to its retail operations, to third-party dealers and distributors, to independent operators of commission agent locations and other consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.
Sunoco LP is the exclusive wholesale supplier of the iconic Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,322 Sunoco-branded company(1)Storage capacity figure includes storage leased from Southwest Gas and third-party operated locations throughoutcompanies.
(2)Includes the Eastnewly constructed 135-mile pipeline and approximately 200 miles of pipeline acquired from EGT.
The following information describes our principal interstate transportation and storage assets:
•FGT extends from South Texas through the Gulf Coast Midwest South Central and Southeast regionsregion of the United States including 245 company operated Sunoco-branded Stripes locations in Texas. Sunoco LP believes itto south Florida. FGT is onethe principal transporter of natural gas to the Florida energy market, delivering approximately 60% of the largestnatural gas consumed in the
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Index to Financial Statements
state. In addition, FGT’s numerous intrastate and interstate pipeline interconnections with major interstate and intrastate natural gas pipelines provide access to diverse natural gas supply sources. FGT’s customers include electric utilities, independent motor fuel distributorspower producers, industrial end-users and local distribution companies. FGT is owned by gallonsCitrus, a 50/50 joint venture with Kinder Morgan, Inc.
•Transwestern Pipeline transports natural gas supply from the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma panhandles. The system has bi-directional capabilities and can access Texas and Midcontinent natural gas market hubs, as well as major western markets in Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
•Panhandle Eastern Pipe Line’s transmission system consists of four large diameter mainline pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle contracts for over 73 Bcf of natural gas storage.
•Trunkline’s transmission system consists of one large diameter mainline pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan. Trunkline has one natural gas storage field located in Louisiana.
•Tiger is a bi-directional system that extends through the heart of the largest distributorsHaynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.
•Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route. Fayetteville Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc.
•Sea Robin Pipeline’s system consists of Chevron, Exxon, Shell and Valero branded motor fueltwo offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico.
•Stingray Pipeline is an interstate natural gas pipeline system with assets located in the United States. In additionwestern Gulf of Mexico and Johnson Bayou, Louisiana.
•Rover Pipeline is a large diameter pipeline which transports natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propanepipeline interconnects in Ohio 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 itMichigan, where the gas is delivered for distribution to markets 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:Ontario, Canada.
1,348 convenience stores•Midcontinent Express Pipeline originates near Bennington, Oklahoma and fuel outlets.traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline system in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc., the operator of the system.
153 independently operated consignment locations where Sunoco LP sells motor fuel•EGT provides natural gas transportation and storage services to customers under commission agent arrangements with such operators;
5,501 convenience storesin Oklahoma, Texas, Arkansas, Louisiana, Missouri and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements;Kansas. EGT has two underground storage facilities in Oklahoma and
2,222 other commercial one underground natural gas storage facility in Louisiana. Through numerous pipeline interconnections along the system and at the Perryville Hub, EGT customers including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.
On January 23, 2018, Sunoco LP sold a portfolio of 1,030 company-operated retail fuel outlets to 7-Eleven.
Retail Operations
As of December 31, 2017, priorhave access to the closing of the amendedMidwest and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately 1,348 convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.
As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise,Northeast markets, as well as motor fuelmost of the major natural gas consuming markets east of the Mississippi River.
•MRT provides natural gas transportation and storage services in Texas, Arkansas, Louisiana, Missouri and Illinois. MRT has underground natural gas storage facilities in Louisiana and Illinois. MRT receives natural gas from a variety of interstate and intrastate pipelines through its interconnections and delivers natural gas primarily to the St. Louis market.
•SESH, a 50/50 joint venture with Enbridge Inc., provides transportation services in Louisiana, Mississippi and Alabama. SESH transports natural gas from the Perryville Hub in Louisiana to its endpoint in Mobile County, Alabama. SESH has interconnections with third party natural gas pipelines and provides access to major Southeast and Northeast markets and transports directly to generating facilities in Mississippi and Alabama and to interconnecting pipelines that supply companies generating electricity for the Florida power market.
•Gulf Run Pipeline, placed in service in December 2022, is a large diameter pipeline that runs from the heart of the Haynesville Shale in East Texas and North Louisiana to the Carthage and Perryville natural gas hubs and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.key markets along the Gulf Coast.
As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.
Investment in Lake Charles LNGRegasification Facility
Lake Charles LNG, providesour wholly-owned subsidiary, owns an LNG import terminal services for shippers by receiving LNG at theand regasification facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification.located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG derives allstorage capacity and the regasification facility has a send out capacity of its revenue from a series1.8 Bcf/d.
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Table of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).Contents
Index to Financial Statements
Liquefaction Project
Lake Charles LNG Export, our wholly-owned subsidiary, is currently developing a natural gas liquefaction facility with BG forproject at the exportsite of LNG. In December 2015,our Lake Charles LNG received authorizationimport terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets.
Since the beginning of 2022, Lake Charles LNG Export has executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC. We have also signed nonbinding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the project. Upon completion of the LNG project, we expect to realize significant incremental cash flows from transportation of natural gas on our Trunkline pipeline system, and other Energy Transfer pipelines upstream from Lake Charles.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to Lake Charles LNG Export. In March 2013, Lake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, Lake Charles LNG Export 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”). In October 2020, the DOE extended the FTA Authorization and Non-FTA Authorization to 30- and 25-year terms, respectively, following first deliveries on or before December 2025, consistent with the FERC to site, construct, and operate facilitiesauthorization for the project. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively, commencing with the completion of construction of the liquefaction facility. In addition, Lake Charles LNG Export received its wetlands permits from the USACE to perform wetlands mitigation work and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced into perform modification and dredging work for the second quarter of 2016 that they will delay making a final investment decision (“FID”) fortemporary and permanent dock facilities at the Lake Charles LNG project and Shell has not advised LCLfacilities.
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Midstream
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The following details our assets in the statusmidstream segment:
Description of AssetsNet Gas Processing Capacity
(MMcf/d)
South Texas2,430 
Ark-La-Tex1,990 
North Central Texas700 
Permian2,815 
Midcontinent3,585 
Eastern200 
The following information describes our principal midstream assets:
South Texas Region:
•Our South Texas assets, which include the Southeast Texas System and the Eagle Ford System, are an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford Shale.
The assets in our Southeast Texas System include a large natural gas gathering system that covers thirteen counties between Austin and Houston, Texas and connects to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. This system also includes three natural gas processing plants (La Grange, Alamo and Brookeland) with an aggregate capacity of 510 MMcf/d. These plants process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines.
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Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The assets in our Eagle Ford System consist of 30-inch and 42-inch natural gas gathering pipelines originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. These assets also include four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with an aggregate capacity of 1.9 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines.
•We own a 60% interest in Edward Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities, and an oil pipeline and oil stabilization facility in South Texas.
Ark-La-Tex Region:
•Our Ark-La-Tex assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, Tristate, Logansport, Magnolia, Olympia, Amoruso, and Lumberjack systems, which collectively include eleven natural gas treating facilities, with aggregate capacity of 3.0 Bcf/d.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that connects to a third party that provides access to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the fourteen natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Lincoln, Rosewood, Mt. Olive, Panola, Sligo and Waskom) have an aggregate capacity of 2.0 Bcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
•The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley plant, which processes rich gas produced from the Barnett Shale and STACK play, with an aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
•The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the project. Inproximity of our system to the eventWaha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that each of LCLwe gather and Shell elect to make an affirmative FID, constructionprocess, including several major interstate and intrastate pipelines serving California, the midcontinent region of the project would be expected to commence promptly thereafterUnited States and first LNG exports would commence about four years later.Texas natural gas markets. The NGL market outlets includes our NGL pipeline system. The Permian Basin Gathering System includes twelve processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keystone, Tippet, Orla, Panther, Rebel, Grey Wolf and Arrowhead) with an aggregate processing capacity of 2.6 Bcf/d and one natural gas conditioning facility with an aggregate capacity of 200 MMcf/d.

•We own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of the joint venture.
Asset Overview•The Partnership previously owned a 50% membership interest in Ranch Westex JV LLC, which was sold in 2022.
InvestmentMidcontinent Region:
•The Midcontinent Systems are located in ETP
The descriptions below include summaries of significant assets within ETP’s operations. Amounts, such as capacities, volumes and miles includedthree large natural gas producing regions in the descriptions belowUnited States: the Hugoton Basin in southwest Kansas, the Anadarko Basin in the Texas Panhandle and Oklahoma, including the STACK and SCOOP plays, and the Arkoma Basin in Eastern Oklahoma and Arkansas. These mature basins have continued to provide generally long-lived, predictable production volumes. Our Midcontinent assets are approximateextensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include 24 natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Hamlin, Spearman, Crescent, Rose Valley, Hopeton, Bradley, Bradley II, McClure, Wheeler, South Canadian, Clinton, Roger Mills, Canute, Cox City, Thomas, Calumet and Wetumka) with an aggregate capacity of approximately 3.1 Bcf/d.
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•We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are based on information currently available; such amountstherefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
•We own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
•We own a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
•In September 2022, we acquired Woodford Express, LLC, which has cryogenic gas processing and treatment capacity of 450 MMcf/d and over 200 miles of gathering lines that are subjectconnected to change based on future events or additional information.Energy Transfer’s pipeline network.
Eastern Region:
•The Eastern Region assets are located in eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica Shales. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipelines, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.
•We also own a 51% membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
•We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, and which delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.
NGL and Refined Products Transportation and Services
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The following details the assets in ETP’s operations:
Intrastate Transportationour NGL and Storage
The following details pipelines and storage facilities in ETP’s intrastaterefined products transportation and storage operations:services segment:
Description of AssetsMiles of Liquids PipelineNGL Fractionation / Processing Capacity
(MBbls/d)		Working Storage Capacity
(MBbls)
Liquids Pipelines:
Gulf Coast NGL Express900 — — 
West Texas Gateway510 — — 
Other Permian Basin NGL1,600 — — 
Mariner East680 — — 
Mariner West450 — — 
Mont Belvieu to Nederland270 
White Cliffs(1)
540 — — 
Other NGL600 — — 
Liquids Fractionation and Storage Facilities:
Mont Belvieu— 940 58,000 
Spindletop— — 8,000 
ET Geismar Olefins(2)
100 35 — 
Hattiesburg— — 5,200 
Cedar Bayou— — 1,600 
NGL Terminals:
Nederland— — 1,900 
Orbit Gulf Coast— — 1,200 
Marcus Hook— — 6,000 
Inkster— — 860 
Refined Products Pipelines:
Eastern region1,580 — — 
Midcontinent region440 — — 
Southwest region550 — — 
Inland600 — — 
JC Nolan Pipeline500 — — 
Refined Products Terminals:
Eagle Point— — 6,700 
Marcus Hook Terminal— — 930 
Marcus Hook Tank Farm— — 1,900 
Marketing Terminals— — 7,700 
JC Nolan Terminal— — 130 
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline Pipeline Throughput Capacity
(Bcf/d)		 Working Storage Capacity
(Bcf/d)
ET Fuel System 100% 2,780
 5.2
 11.2
Oasis Pipeline 100% 750
 2.3
 —
HPL System 100% 3,920
 5.3
 52.5
East Texas Pipeline 100% 460
 2.4
 —
RIGS Haynesville Partnership Co. 49.99% 450
 2.1
 —
Comanche Trail Pipeline 16% 195
 1.1
 —
Trans-Pecos Pipeline 16% 143
 1.4
 —
(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
(2)Additionally, the ET Geismar Olefins off-gas processing facility has inlet volume capacity of 54 MMcf/d.
The following information describes ETP’sour principal intrastateNGL and refined products transportation and storageservices assets:
•Gulf Coast NGL Express is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelines, with throughput capacity of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
•West Texas Gateway transports mixed NGLs produced in the Permian Basin and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.
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•The Mariner East Pipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports NGLs from the Marcellus and Utica Shales in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets.
•The Mont Belvieu to Nederland Pipeline System consists of three pipelines and delivers export-grade propane, butane and natural gasoline from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a total throughput capacity of approximately 530 MBbls/d. In addition, it includes an export-grade ethane pipeline utilized for our Orbit Gulf Coast joint venture as described below.
•The Mariner West pipeline provides transportation of ethane from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d.
•The White Cliffs NGL pipeline, in which we have 51% ownership interest, transports mixed NGLs produced in the DJ Basin to Cushing, Oklahoma where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90 MBbls/d.
•Other NGL pipelines include the 127-mile Justice pipeline, the 45-mile Freedom pipeline, the 20-mile Spirit pipeline and a 50% interest in the 87 mile Liberty pipeline.
•Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 58 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators. We have an additional 8 MMBbls of salt dome capacity at our Spindletop facility which we acquired in March 2022, and is located in Beaumont, Texas.
•Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Gulf Coast NGL Express, West Texas Gateway and Justice pipelines.
•ET FuelGeismar Olefins consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
•The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-based cash flows.
•The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.
•The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs in connection with the Mont Belvieu to Nederland Pipeline System, which provides transportation of propane, butane and natural gasoline products from our Mont Belvieu, Texas storage and fractionation complex to the Nederland Terminal, where such products can be exported via ship.
•The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 200 MBbls/d, delivering from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas, as well as a 180 MBbls/d ethane refrigeration facility and 1.2 MMBbls of storage capacity.
•The Marcus Hook Terminal includes fractionation, terminalling and storage assets, with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground NGL refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Terminal currently serves someas an off-take outlet for our Mariner East Pipeline System.
The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.
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•The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use the Inkster terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
•The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product pipelines in eastern, central and north central Pennsylvania, 8-inch refined products pipeline in western New York and various diameter refined products pipelines in New Jersey (including 80 miles of the most prolific production areas16-inch diameter Harbor Pipeline).
•The midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan.
•The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products pipeline.
•The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio.
•The JC Nolan Pipeline, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 36 MBbls/d.
•We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.
•In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•The JC Nolan Terminal, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, provides diesel fuel storage in Midland, Texas.
•This segment also includes the following joint ventures: a 15% membership interest in Explorer, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur and Houston, Texas and extends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.
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Crude Oil Transportation and Services
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The following details our pipelines and terminals in its crude oil transportation and services operations:
Description of AssetsOwnership InterestMiles of Crude PipelineWorking Storage Capacity
(MBbls)
Dakota Access Pipeline36.40 %1,170 — 
Energy Transfer Crude Oil Pipeline36.40 %745 — 
Bayou Bridge Pipeline60 %210 — 
Permian Express Pipelines87.7 %1,760 — 
Wattenberg Oil Trunkline100 %75 360 
White Cliffs Pipeline(1)
51 %530 100 
Maurepas Pipeline51 %35 — 
Other Crude Oil Pipelines100 %6,790 — 
Nederland Terminal100 %— 31,000 
Fort Mifflin Terminal100 %— 3,300 
Eagle Point Terminal100 %— 1,800 
Midland Terminal100 %— 1,000 
Marcus Hook Terminal100 %— 1,000 
Houston Terminal100 %— 18,200 
Cushing Terminal100 %— 7,600 
Patoka, Illinois Terminal87.7 %— 1,900 
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(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:
Crude Oil Pipelines
Our crude oil pipelines consist of approximately 11,315 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including our wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, Mid-Valley and Wattenberg Oil Trunkline. Additionally, we have equity ownership interests in six crude oil pipelines. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
•Bakken Pipeline. TheDakota Access Pipeline and Energy Transfer Crude Oil Pipeline are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is compriseda 1,915-mile pipeline that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of intrastatePatoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas. The Bakken Pipeline has a capacity of up to 750 MBbls/d. The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
The Dakota Access Pipeline consists of approximately 1,170 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.
The Energy Transfer Crude Oil Pipeline consists of approximately 675 miles of mostly 30-inch converted natural gas pipeline and related natural gas70 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
•Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between Energy Transfer and a subsidiary of Phillips 66, in which we have a 60% ownership interest and serve as the operator of the pipeline. Phase I of the pipeline is a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, and Phase II of the pipeline, is a 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana.Bayou Bridge Pipeline has a capacity of approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
•Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview, Louisiana Access, Longview to Louisiana and Nederland Access pipelines. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, with origins in multiple locations in West Texas.
•White Cliffs Crude Pipeline. White Cliffs Pipeline owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
•Maurepas Pipeline. The Maurepas Pipeline consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.
•Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma and Kansas. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma and Kansas systems to Cushing, Oklahoma. We are one of the
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largest purchasers of crude oil from producers in the area and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
We also own crude oil and condensate gathering assets in the Anadarko Basin and the Williston Basin. The Anadarko Basin assets were designed and built to serve the crude oil and condensate production in the SCOOP and STACK plays. A portion of these operations are conducted through Enable South Central Pipeline, a joint venture with a subsidiary of CVR Energy, Inc., which is operated by us and in which we own a 60% membership interest. The Williston Basin crude oil and produced water gathering assets were designed and built to receive crude oil on pipelines near our customers’ wells for delivery to third-party transportation pipelines, and produced water gathering pipelines for delivery to third-party disposal wells.
Crude Oil Terminals
•Nederland. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage facilities.and distribution services for refiners and other large transporters of crude oil and NGLs. The ET Fuel Systemterminal receives, stores, and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has many interconnectionsa total storage capacity of approximately 31 MMBbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland Terminal can receive crude oil at three of its six ship docks and three of its four barge berths. The three ship docks are capable of receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls. The terminal also has crude oil rail unloading facilities, including steam availability for heating heavy oils prior to loading.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 MMBbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues primarily by providing direct accessterm or spot storage services and throughput capabilities to power plants, other intrastatea number of customers.
•Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and interstateincludes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks. The Darby Creek tank farm is a primary crude oil storage terminal that receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines and has bi-directional capabilities. Ita total storage capacity of approximately 2.7 MMBbls.
•Eagle Point. The Eagle Point terminal is strategically located near high-growth production areasin Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1.8 MMBbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•Midland. The Midland terminal is located in Midland, Texas and includes approximately 1 MMBbls of crude oil storage, a combined 20 lanes of truck loading and unloading, and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, TexasPermian Express 2 pipeline.
•Marcus Hook. The Marcus Hook Terminal can receive crude oil via marine vessel and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
can deliver via marine vessel and pipeline. The ET Fuel System also includes the Bethel natural gasterminal has a total active crude oil storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, andapproximately 1 MMBbls.
•Patoka, Illinois. The Patoka, Illinois terminal is a tank farm owned by the Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas SystemPEP joint venture and is an important component to maximizing its Southeast Texas System’s profitability.located in Marion County, Illinois. The Oasis pipeline enhances the Southeast Texas System by (i) providing accessfacility includes 234 acres of owned land and provides for natural gasapproximately 1.9 MMBbls of crude oil storage.
•Houston. The Houston Terminal consists of storage tanks located on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas

in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and Agua Dulce, as well as ETP’s Bammel storage facility.
The Bammel storagetransport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located nearfive deep-water ship docks on the Houston Ship Channel market areacapable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.
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•Cushing. The Cushing Terminal has approximately 7.6 MMBbls of crude oil storage, of which 5.6 MMBbls are leased to customers and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the Katy Hub,White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and is ideally suited to provide a physical backup for on-systemtwo-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.
Crude Oil Acquisition and off-system customers. As of December 31, 2017, ETP hadMarketing
Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 10.8 Bcf committed under fee-based arrangements with third parties363 crude oil transport trucks, 350 trailers and approximately 36.9 Bcf stored in the facility for ETP’s own account.
The East Texas Pipeline connects three treating166 crude oil truck unloading facilities, one of which ETP owns, with its Southeast Texas System. The East Texasas well as third-party truck, rail, pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.marine assets.
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.
Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.
Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
Interstate Transportation and Storage
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The following details our pipelines in the interstate transportation and storage segment:
Description of AssetsOwnership InterestMiles of Natural Gas PipelinePipeline Throughput Capacity
(Bcf/d)		Working Storage Capacity
(Bcf)
Florida Gas Transmission (“FGT”)50 %5,380 3.9 — 
Transwestern Pipeline100 %2,590 2.1 — 
Panhandle Eastern Pipe Line (1)
100 %6,300 2.8 73.0 
Trunkline100 %2,190 0.9 13.0 
Tiger100 %200 2.4 — 
Fayetteville Express Pipeline50 %185 2.0 — 
Sea Robin Pipeline100 %740 2.0 — 
Stingray Pipeline100 %290 0.4 — 
Rover Pipeline32.6 %720 3.4 — 
Midcontinent Express Pipeline50 %510 1.8 — 
Enable Gas Transmission (“EGT”)100 %5,700 4.8 29.3 
Mississippi River Transmission (“MRT”)100 %1,600 1.7 48.9 
Southeast Supply Header (“SESH”)50 %290 1.1 — 
Gulf Run Pipeline100 %
335(2)
3.0(2)
— 
(1)Storage capacity figure includes storage leased from Southwest Gas and third-party companies.
(2)Includes the newly constructed 135-mile pipeline and approximately 200 miles of pipeline acquired from EGT.
The following information describes ETP’sour principal interstate transportation and storage assets:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission Pipeline 50% 5,360
 3.1
 —
Transwestern Pipeline 100% 2,570
 2.1
 —
Panhandle Eastern Pipe Line 100% 5,980
 2.8
 83.9
Trunkline Gas Pipeline 100% 2,220
 0.9
 13.0
Tiger Pipeline 100% 195
 2.4
 —
Fayetteville Express Pipeline 50% 185
 2.0
 —
Sea Robin Pipeline 100% 830
 2.0
 —
Rover Pipeline 32.6% 713
 3.25
 —
Midcontinent Express Pipeline 50% 500
 1.8
 —
Gulf States 100% 10
 0.1
 —
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,360 miles of pipelines extending•FGT extends from southSouth Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66%approximately 60% of the natural gas consumed in the
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state. In addition, FGT’s system operatesnumerous intrastate and maintains over 81 interconnectsinterstate pipeline interconnections with major interstate and intrastate natural gas pipelines which provide FGT’s customers access to diverse natural gas producing regions.supply sources. FGT’s customers include electric utilities, independent power producers, industrialsindustrial end-users and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture between ETP and KMI.with Kinder Morgan, Inc.
The •Transwestern Pipeline is an open-access interstatetransports natural gas pipeline extendingsupply from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico;Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado;Colorado, and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural

gas sources from the San Juan BasinThe system has bi-directional capabilities and surrounding producing areas can be delivered eastward toaccess Texas intrastate and mid-continent connecting pipelines andMidcontinent natural gas market hubs, as well as westward tomajor western markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
The •Panhandle Eastern Pipe Line’s transmission system consists of four large diameter mainline pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle contracts for over 73 Bcf of natural gas storage.
The Trunkline Gas Pipeline’s•Trunkline’s transmission system consists of one large diameter mainline pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
The Tiger Pipeline is an approximately 195-mile interstate Trunkline has one natural gas pipeline withstorage field located in Louisiana.
•Tiger is a bi-directional capabilities,system that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with interconnects to at least sevenmultiple interstate pipelines at various points in Louisiana.pipelines.
The •Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas and continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company into Panola County, Mississippi. TheMississippi with multiple pipeline interconnections along the route. Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.Kinder Morgan, Inc.
The •Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systemspipelines extending approximately 120 miles into the Gulf of Mexico.
The •Stingray Pipeline is an interstate natural gas pipeline system with assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana.
•Rover Pipeline is a new 713-mile natural gaslarge diameter pipeline designed to transport 3.25 Bcf/d of domestically producedwhich transports natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the Marcellus and Utica Shale production areasgas is delivered for distribution to markets across the United States, as well as into the Union Gas Dawn Storage Hub into Ontario, Canada, for redistribution back into the United States or into the Canadian market.Canada.
The •Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeastoriginates near Bennington, Oklahoma through northeast Texas,and traverses northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline Systemsystem in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.Kinder Morgan, Inc., the operator of the system.
•EGT provides natural gas transportation and storage services to customers in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas. EGT has two underground storage facilities in Oklahoma and one underground natural gas storage facility in Louisiana. Through numerous pipeline interconnections along the system and at the Perryville Hub, EGT customers have access to the Midwest and Northeast markets, as well as most of the major natural gas consuming markets east of the Mississippi River.
•MRT provides natural gas transportation and storage services in Texas, Arkansas, Louisiana, Missouri and Illinois. MRT has underground natural gas storage facilities in Louisiana and Illinois. MRT receives natural gas from a variety of interstate and intrastate pipelines through its interconnections and delivers natural gas primarily to the St. Louis market.
•SESH, a 50/50 joint venture with Enbridge Inc., provides transportation services in Louisiana, Mississippi and Alabama. SESH transports natural gas from the Perryville Hub in Louisiana to its endpoint in Mobile County, Alabama. SESH has interconnections with third party natural gas pipelines and provides access to major Southeast and Northeast markets and transports directly to generating facilities in Mississippi and Alabama and to interconnecting pipelines that supply companies generating electricity for the Florida power market.
•Gulf States ownsRun Pipeline, placed in service in December 2022, is a 10-mile interstatelarge diameter pipeline that extendsruns from Harrison County,the heart of the Haynesville Shale in East Texas and North Louisiana to Caddo Parish,the Carthage and Perryville natural gas hubs and other key markets along the Gulf Coast.
Regasification Facility
Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d.
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Liquefaction Project
Lake Charles LNG Export, our wholly-owned subsidiary, is developing a natural gas liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. The project as currently designed is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets.
Since the beginning of 2022, Lake Charles LNG Export has executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC. We have also signed nonbinding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the project. Upon completion of the LNG project, we expect to realize significant incremental cash flows from transportation of natural gas on our Trunkline pipeline system, and other Energy Transfer pipelines upstream from Lake Charles.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to Lake Charles LNG Export. In March 2013, Lake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, Lake Charles LNG Export 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”). In October 2020, the DOE extended the FTA Authorization and Non-FTA Authorization to 30- and 25-year terms, respectively, following first deliveries on or before December 2025, consistent with the FERC authorization for the project. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively, commencing with the completion of construction of the liquefaction facility. In addition, Lake Charles LNG Export received its wetlands permits from the 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.
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Midstream
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The following details ETP’sour assets in itsthe midstream operations:segment:
Description of Assets
Net Gas Processing Capacity
(MMcf/d)
 
Net Gas Treating Capacity
(MMcf/d)
South Texas Region:   
Southeast Texas System410
 510
Eagle Ford System1,920
 1,808
Ark-La-Tex Region1,025
 1,186
North Central Texas Region715
 212
Permian Region1,943
 1,580
Mid-Continent Region885
 20
Eastern Region—
 70
Description of AssetsNet Gas Processing Capacity
(MMcf/d)
South Texas2,430 
Ark-La-Tex1,990 
North Central Texas700 
Permian2,815 
Midcontinent3,585 
Eastern200 
The following information describes ETP’sour principal midstream assets:
South Texas Region:
The•Our South Texas assets, which include the Southeast Texas System isand the Eagle Ford System, are an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford shale formation. Shale.
The assets in our Southeast Texas System isinclude a large natural gas gathering system coveringthat covers thirteen counties between Austin and Houston. This system is connectedHouston, Texas and connects to the Katy Hub through the East TexasETC Katy Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas SystemThis system also includes twothree natural gas processing plantplants (La Grange, Alamo and Alamo)Brookeland) with aggregate capacity of 410 MMcf/d and natural gas treating facilities withan aggregate capacity of 510 MMcf/d. The La Grange and Alamo processingThese plants are natural gas processing plants that process

the rich gas that flows through ETP’sour gathering system to produce residue gas and NGLs. Residue gas is delivered into itsour intrastate pipelines and NGLs are delivered into ETP’sour NGL pipelinespipelines.
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Index to Lone Star.Financial Statements
ETP’sOur treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’sour system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The assets in our Eagle Ford Gathering System consistsconsist of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both ETP’sour King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includesThese assets also include four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with an aggregate capacity of 1,920 MMcf/d and multiple natural gas treating facilities with combined capacity of 1,808 MMcf/1.9 Bcf/d. ETP’sOur Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to itsour intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’sour NGL pipelines for delivery of NGLs to Lone Star.pipelines.
•We own a 60% interest in Edward Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities, and an oil pipeline and oil stabilization facility in South Texas.
Ark-La-Tex Region:
ETP’s Northern Louisiana•Our Ark-La-Tex assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’sour Tiger Pipeline. ETP’spipeline. Our Northern Louisiana assets include the Bistineau, Creedence, Tristate, Logansport, Magnolia, Olympia, Amoruso, and Tristate Systems,Lumberjack systems, which collectively include threeeleven natural gas treating facilities, with aggregate capacity of 1,186 MMcf/3.0 Bcf/d.
ETP’s PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to ETP’s processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from ETP’s processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s processing plants.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an interstate NGL pipeline.pipeline that connects to a third party that provides access to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the eightfourteen natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Lincoln, Rosewood, Mt. Olive, Panola, Sligo and Brookeland)Waskom) have an aggregate capacity of 1,025 MMcf/2.0 Bcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, ETP offersas well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
•The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. ETP’sOur North Central Texas assets include itsour Godley and Crescent plants,plant, which processprocesses rich gas produced from the Barnett Shale and STACK play, with an aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212700 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
•The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of ETP’sour system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that ETP gatherswe gather and processes,process, including several major interstate and intrastate pipelines serving California, the mid-continentmidcontinent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines.our NGL pipeline system. The Permian Basin Gathering System includes tentwelve processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston,Keystone, Tippet, Orla, Panther, Rebel, Grey Wolf and Rebel)Arrowhead) with an aggregate processing capacity of 1,618 MMcf/d, treating capacity of 1,580 MMcf/2.6 Bcf/d and one natural gas conditioning facility with an aggregate capacity of 200 MMcf/d.
ETP owns•We own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operatesWe operate the plant and related facilities on behalf of Mi Vida JV.the joint venture.

ETP owns•The Partnership previously owned a 33.33%50% membership interest in Ranch Westex JV LLC, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formationswas sold in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.2022.
Mid-ContinentMidcontinent Region:
•The Mid-ContinentMidcontinent Systems are located in twothree large natural gas producing regions in the United States,States: the Hugoton Basin in southwest Kansas, and the Anadarko Basin in westernthe Texas Panhandle and Oklahoma, including the STACK and SCOOP plays, and the Arkoma Basin in Eastern Oklahoma and the Texas Panhandle.Arkansas. These mature basins have continued to provide generally long-lived, predictable production volume. ETP’s Mid-Continentvolumes. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-ContinentMidcontinent Systems include fourteen24 natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, CargrayCrescent, Rose Valley, Hopeton, Bradley, Bradley II, McClure, Wheeler, South Canadian, Clinton, Roger Mills, Canute, Cox City, Thomas, Calumet and Gray)Wetumka) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacityapproximately 3.1 Bcf/d.
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Table of 20 MMcf/d.Contents
ETP operates its Mid-ContinentIndex to Financial Statements
•We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
ETP also owns•We own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
•We own a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
•In September 2022, we acquired Woodford Express, LLC, which has cryogenic gas processing and treatment capacity of 450 MMcf/d and over 200 miles of gathering lines that are connected to Energy Transfer’s pipeline network.
Eastern Region:
•The Eastern Region assets are located in nineeleven counties in Pennsylvania, threefour counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. ETP’sShales. Our Eastern Region assets include approximately 500600 miles of natural gas gathering pipeline,pipelines, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh watersystems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline system and Ohio gathering assets are held by jointly-owned entities.systems.
ETP•We also ownsown a 51% membership interest in Aqua – PVR,ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
ETP and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC,•We own a 75% and 25% membership interest respectively, in the ORS joint venture.ORS. On behalf of ORS, ETP operates ORS’swe operate its Ohio Utica River System, (the “ORS System”), which consists of 47 miles of 36-inch, and 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, thatand which delivers up to 2.13.6 Bcf/d to Rockies Express Pipeline, (“REX”), Texas Eastern Transmission, Leach Xpress, Rover and others.DEO TPL-18.

NGL and Refined Products Transportation and Services
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The following details the assets in ETP’sour NGL and refined products transportation and services operations:segment:
Description of AssetsMiles of Liquids PipelineNGL Fractionation / Processing Capacity
(MBbls/d)		Working Storage Capacity
(MBbls)
Liquids Pipelines:
Gulf Coast NGL Express900 — — 
West Texas Gateway510 — — 
Other Permian Basin NGL1,600 — — 
Mariner East680 — — 
Mariner West450 — — 
Mont Belvieu to Nederland270 
White Cliffs(1)
540 — — 
Other NGL600 — — 
Liquids Fractionation and Storage Facilities:
Mont Belvieu— 940 58,000 
Spindletop— — 8,000 
ET Geismar Olefins(2)
100 35 — 
Hattiesburg— — 5,200 
Cedar Bayou— — 1,600 
NGL Terminals:
Nederland— — 1,900 
Orbit Gulf Coast— — 1,200 
Marcus Hook— — 6,000 
Inkster— — 860 
Refined Products Pipelines:
Eastern region1,580 — — 
Midcontinent region440 — — 
Southwest region550 — — 
Inland600 — — 
JC Nolan Pipeline500 — — 
Refined Products Terminals:
Eagle Point— — 6,700 
Marcus Hook Terminal— — 930 
Marcus Hook Tank Farm— — 1,900 
Marketing Terminals— — 7,700 
JC Nolan Terminal— — 130 
Description of Assets
Miles of Liquids Pipeline (2)
 
Pipeline Throughput Capacity
(MBbls/d)
 
NGL Fractionation / Processing Capacity
(MBbls/d)
 
Working Storage Capacity
(MBbls)
Liquids Pipelines:       
Lone Star Express535
 507
 —
 —
West Texas Gateway Pipeline512
 240
 —
 —
Lone Star1,617
 120
 —
 —
Mariner East300
 70
    
Mariner South67
 200
    
Mariner West395
 50
    
Other NGL Pipelines645
 591
 —
 —
Liquids Fractionation and Services Facilities:       
Mont Belvieu Facilities163
 42
 520
 50,000
Sea Robin Processing Plant1
—
 —
 26
 —
Refinery Services1
103
 —
 25
 —
Hattiesburg Storage Facilities—
 —
 —
 3,000
NGLs Terminals:       
Nederland—
 —
 —
 1,000
Marcus Hook Industrial Complex—
 —
 90
 5,000
Inkster—
 —
 —
 1,000
Refined Products Pipelines2,200
 800
 —
 —
Refined Products Terminals:       
Eagle Point—
 —
 —
 6,000
Marcus Hook Industrial Complex—
 —
 —
 1,000
Marcus Hook Tank Farm—
 —
 —
 2,000
Marketing Terminals—
 —
 —
 8,000
(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
(1)
(2)Additionally, the ET Geismar Olefins off-gas processing facility has inlet volume capacity of 54 MMcf/d.
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.
(2)
Miles of pipeline as reported to PHMSA.
The following information describes ETP’sour principal NGL and refined products transportation and services assets:
The Lone Star•Gulf Coast NGL Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelinepipelines, with throughput capacity of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
The •West Texas Gateway Pipeline transports mixed NGLs produced in the Permian and Delaware BasinsBasin and the Eagle Ford Shale to Mont Belvieu, Texas.Texas and has a throughput capacity of approximately 240 MBbls/d.
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Index to Financial Statements
•The Mariner East pipelinePipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including ETP’sour Marcus Hook Industrial ComplexTerminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets.
•The first phaseMont Belvieu to Nederland Pipeline System consists of the project, referred to as Mariner East 1, consisted of interstatethree pipelines and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the second quarter of 2018.

The Mariner South pipeline is part of a joint project with Lone Star to deliverdelivers export-grade propane, butane and butane productsnatural gasoline from Lone Star’sour Mont Belvieu, Texas storage and fractionation complex to ETP’sour marine terminal in Nederland, Texas.Texas and has a total throughput capacity of approximately 530 MBbls/d. In addition, it includes an export-grade ethane pipeline utilized for our Orbit Gulf Coast joint venture as described below.
•The Mariner West pipeline provides transportation of ethane from the Marcellus shaleShale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarterborder and has a throughput capacity of 2013, with capacity to transport approximately 50 MBbls/d.
Refined products pipelines include approximately 2,200 miles of refined products pipelines•The White Cliffs NGL pipeline, in several regions of the United States. The pipelines primarily provide transportationwhich we have 51% ownership interest, transports mixed NGLs produced in the northeast, midwest,DJ Basin to Cushing, Oklahoma where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and southwest United States markets. These operations include ETP’s controlling financial interest in Inland Corporation (“Inland”). The mixhas a throughput capacity of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.approximately 90 MBbls/d.
•Other NGL pipelines include the 127-mile Justice pipeline, with capacity of 375 MBbls/d, the 45-mile Freedom pipeline, with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile87 mile Liberty pipeline with a capacity of 140 MBbls/d.pipeline.
ETP’s•Our Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bblsapproximately 58 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined productproducts pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators. We have an additional 8 MMBbls of salt dome capacity at our Spindletop facility which we acquired in March 2022, and is located in Beaumont, Texas.
ETP’s•Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone StarGulf Coast NGL Express, pipelineWest Texas Gateway and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.pipelines.
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
Refinery Services•ET Geismar Olefins consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
•The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls5 MMBbls of salt dome capacity, providing 100% fee-based cash flows.
•The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.
•The Nederland terminal,Terminal, in addition to crude oil activities, also provides approximately 1 million Bbls1.9 MMBbls of storage and distribution services for NGLs in connection with the Mariner South pipeline,Mont Belvieu to Nederland Pipeline System, which provides transportation of propane, butane and butanenatural gasoline products from theour Mont Belvieu, regionTexas storage and fractionation complex to the Nederland terminal,Terminal, where such products can be exported via ship.
•The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 200 MBbls/d, delivering from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas, as well as a 180 MBbls/d ethane refrigeration facility and 1.2 MMBbls of storage capacity.
•The Marcus Hook Industrial ComplexTerminal includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million BblsMMBbls of NGL storage capacity in underground caverns, 3 million Bbls4 MMBbls of above-ground NGL refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls.MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLsNGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial ComplexTerminal currently serves as an off-take outlet for theour Mariner East 1Pipeline System.
The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls. The terminal receives and delivers refined products via pipeline and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.primarily provides terminalling services to support movements on our refined products pipelines.
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Index to Financial Statements
•The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls860 MBbls of NGLs. ETP usesWe use the Inkster terminal'sterminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
ETP•The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product pipelines in eastern, central and north central Pennsylvania, 8-inch refined products pipeline in western New York and various diameter refined products pipelines in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
•The midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan.
•The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products pipeline.
•The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio.
•The JC Nolan Pipeline, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 4036 MBbls/d.
•We have 37 refined products terminals with an aggregate storage capacity of approximately 8 million BblsMMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

•In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million Bbls,7 MMBbls and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•The Marcus Hook Tank Farm hasJC Nolan Terminal, a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on ETP’s refined products pipelines.
The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 milesjoint venture between a wholly-owned subsidiary of the 16-inch diameter Harbor Pipeline).Partnership and a wholly-owned subsidiary of Sunoco LP, provides diesel fuel storage in Midland, Texas.
The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines•This segment also includes the following joint ventures: a 15% membership interest in Ohio, approximately 85 miles of 6-inch to 12-inch refined productsExplorer, a 1,850-mile pipeline which originates from refining centers in Western PennsylvaniaBeaumont, Port Arthur and approximately 52 miles of 8-inch refined products pipeline in Michigan.
The Southwest refined products pipelines is located in EasternHouston, Texas and consists primarilyextends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.
25
Table of approximately 300 miles of 8-inch diameter refined products pipeline.Contents
The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.Index to Financial Statements
Crude Oil Transportation and Services
et-20221231_g8.jpg
The following details ETP’sour pipelines and terminals in its crude oil transportation and services operations:
Description of AssetsOwnership InterestMiles of Crude PipelineWorking Storage Capacity
(MBbls)
Dakota Access Pipeline36.40 %1,170 — 
Energy Transfer Crude Oil Pipeline36.40 %745 — 
Bayou Bridge Pipeline60 %210 — 
Permian Express Pipelines87.7 %1,760 — 
Wattenberg Oil Trunkline100 %75 360 
White Cliffs Pipeline(1)
51 %530 100 
Maurepas Pipeline51 %35 — 
Other Crude Oil Pipelines100 %6,790 — 
Nederland Terminal100 %— 31,000 
Fort Mifflin Terminal100 %— 3,300 
Eagle Point Terminal100 %— 1,800 
Midland Terminal100 %— 1,000 
Marcus Hook Terminal100 %— 1,000 
Houston Terminal100 %— 18,200 
Cushing Terminal100 %— 7,600 
Patoka, Illinois Terminal87.7 %— 1,900 
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Index to Financial Statements
Description of Assets
Miles of Crude Pipeline (1)
Working Storage Capacity
(MBbls)
Dakota Access Pipeline1,172
—
Energy Transfer Crude Oil Pipeline743
—
Bayou Bridge Pipeline49
—
Permian Express Pipelines1,712
—
Other Crude Oil Pipelines5,682
—
Nederland Terminal—
26,000
Fort Mifflin Terminal—
570
Eagle Point Terminal—
1,000
Midland Terminal—
2,000
Marcus Hook Industrial Complex—
1,000
Patoka, Illinois Terminal—
2,000
(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
(1)
Miles of pipeline as reported to PHMSA.
ETP’sOur crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details ETP’sour assets in itsthe crude oil transportation and services operations:segment:
Crude Oil Pipelines
ETP’sOur crude oil pipelines consist of approximately 9,35811,315 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including ETP’sour wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, (“PET”),Mid-Valley and Mid-Valley Pipeline Company (“Mid-Valley”).Wattenberg Oil Trunkline. Additionally, ETP haswe have equity ownership interests in twosix crude oil pipelines.

ETP’s Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’sOur crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
•Bakken Pipeline. TheDakota Access Pipeline and ETCOEnergy Transfer Crude Oil Pipeline are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile1,915-mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’sour crude terminal in Nederland, Texas.
The Bakken Pipeline has a capacity of up to 750 MBbls/d. The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
The Dakota Access went into service on June 1, 2017 andPipeline consists of approximately 1,1721,170 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCOEnergy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 andThe Energy Transfer Crude Oil Pipeline consists of more than 743 miles consisting of 678approximately 675 miles of mostly 30-inch converted natural gas pipeline and 6570 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
•Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETPEnergy Transfer and a subsidiary of Phillips 66, in which ETP haswe have a 60% ownership interest and servesserve as the operator of the pipeline. Phase I of the pipeline which consists ofis a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016.and Phase II of the pipeline, which will consist ofis a 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Louisiana.Bayou Bridge Pipeline will havehas a capacity expandable toof approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
•Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview, and Louisiana Access, pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil.Nederland Access pipelines. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, whichwith origins in multiple locations in WesternWest Texas.
•White Cliffs Crude Pipeline. White Cliffs Pipeline owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
•Maurepas Pipeline. The Maurepas Pipeline consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.
•Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma.Oklahoma and Kansas. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma systemand Kansas systems to Cushing.Cushing, Oklahoma. We are one of the
27
Table of Contents
Index to Financial Statements
largest purchasers of crude oil from producers in the state,area and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
We also own crude oil and condensate gathering assets in the Anadarko Basin and the Williston Basin. The Anadarko Basin assets were designed and built to serve the crude oil and condensate production in the SCOOP and STACK plays. A portion of these operations are conducted through Enable South Central Pipeline, a joint venture with a subsidiary of CVR Energy, Inc., which is operated by us and in which we own a 60% membership interest. The Williston Basin crude oil and produced water gathering assets were designed and built to receive crude oil on pipelines near our customers’ wells for delivery to third-party transportation pipelines, and produced water gathering pipelines for delivery to third-party disposal wells.
Crude Oil Terminals
•Nederland. The Nederland terminal,Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants.. The terminal currently has a total storage capacity of approximately 26 million Bbls31 MMBbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland terminalTerminal can receive crude oil at fourthree of its fivesix ship docks and three of its four barge berths. The fourthree ship docks are capable of receiving over 2 million Bbls/MMBbls/d of crude oil. In addition to ETP’sour crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.MMBbls. The terminal also has crude oil rail unloading facilities, including steam availability for heating heavy oils prior to loading.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has twothree ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/MMBbls/d of crude oil to ETP’sour crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminalTerminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
•Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
docks. The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million Bbls. Darby Creekthat receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oilour pipelines and transports it to the PES refinery via ETP’s pipelines.has a total storage capacity of approximately 2.7 MMBbls.
•Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls1.8 MMBbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls1 MMBbls of crude oil storage, a combined 1420 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.
pipeline.
•Marcus Hook Industrial Complex. Hook. The Marcus Hook Industrial ComplexTerminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.
MMBbls.
•Patoka, Illinois Terminal.Illinois. The Patoka, Illinois terminal is a tank farm and was contributedowned by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls1.9 MMBbls of crude oil storage.
•Houston. The Houston Terminal consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.
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Index to Financial Statements
•Cushing. The Cushing Terminal has approximately 7.6 MMBbls of crude oil storage, of which 5.6 MMBbls are leased to customers and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.
Crude Oil AcquisitionRegasification Facility
Lake Charles LNG, our wholly-owned subsidiary, owns an LNG import terminal and Marketing
ETP’s crude oil acquisitionregasification 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 marketing operations are conducted using ETP’s assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.
All Other
Equity Method Investments
Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

PES. ETPthe regasification facility has a non-controlling interest in PES, comprising 33%send out capacity of PES’ outstanding common units. As discussed in “ETP’s Other Operations and Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.1.8 Bcf/d.
18
Contract Services Operations
Table of Contents
ETP owns and operates a fleet of equipment usedIndex 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.Financial Statements
Compression
ETP owns all of the outstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.
Natural Resources Operations
ETP’s Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. ETP also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2017, ETP owned or controlled approximately 766 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
Liquefaction Project
LCL, an entity whose parentLake Charles LNG Export, our wholly-owned subsidiary, is owned 60% by ETE and 40% by ETP, is in the process of developing a natural gas liquefaction project at the site of ETE’s existing regasification facility inour Lake Charles Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017. On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas CorporationLNG import terminal and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project.regasification facility. The project would utilize existing dock and storage facilities owned by ETELake Charles LNG located on the Lake Charles site. The parties’ determination asLake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the feasibilityonset of the COVID-19 pandemic. The project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supplyas currently designed is fully permitted by federal, state and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the termslocal authorities, has all necessary export licenses and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNGbenefits from the liquefaction facilityinfrastructure related to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.
The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and is obligated to pay reservation fees for 100%other assets.
Since the beginning of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by2022, Lake Charles LNG Export has executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC. We have also signed nonbinding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the remaining acres areproject. Upon completion of the LNG project, we expect to be leased by LCL under a long-term leaserealize significant incremental cash flows from thetransportation of natural gas on our Trunkline pipeline system, and other Energy Transfer pipelines upstream from Lake Charles Harbor and Terminal District.Charles.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL.Lake Charles LNG Export. In March 2013, LCLLake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCLLake Charles LNG Export 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”). In October 2020, the DOE extended the FTA Authorization and Non-FTA Authorization to 30- and 25-year terms, respectively, following first deliveries on or before December 2025, consistent with the FERC authorization for the project. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively.

ETP hasrespectively, commencing with the completion of construction of the liquefaction facility. In addition, Lake Charles LNG Export received its wetlands permits from the United States Army Corps of Engineers (“USACE”)USACE to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
Investment
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Midstream
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The following details our assets in Sunoco LPthe midstream segment:
Description of AssetsNet Gas Processing Capacity
(MMcf/d)
South Texas2,430 
Ark-La-Tex1,990 
North Central Texas700 
Permian2,815 
Midcontinent3,585 
Eastern200 
The following information describes our principal midstream assets:
South Texas Region:
•Our South Texas assets, which include the Southeast Texas System and the Eagle Ford System, are an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford Shale.
The assets in our Southeast Texas System include a large natural gas gathering system that covers thirteen counties between Austin and Houston, Texas and connects to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. This system also includes three natural gas processing plants (La Grange, Alamo and Brookeland) with an aggregate capacity of 510 MMcf/d. These plants process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines.
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Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The assets in our Eagle Ford System consist of 30-inch and 42-inch natural gas gathering pipelines originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. These assets also include four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with an aggregate capacity of 1.9 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines.
•We own a 60% interest in Edward Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities, and an oil pipeline and oil stabilization facility in South Texas.
Ark-La-Tex Region:
•Our Ark-La-Tex assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, Tristate, Logansport, Magnolia, Olympia, Amoruso, and Lumberjack systems, which collectively include eleven natural gas treating facilities, with aggregate capacity of 3.0 Bcf/d.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that connects to a third party that provides access to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the fourteen natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Lincoln, Rosewood, Mt. Olive, Panola, Sligo and Waskom) have an aggregate capacity of 2.0 Bcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
•The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley plant, which processes rich gas produced from the Barnett Shale and STACK play, with an aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
•The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the midcontinent region of the United States and Texas natural gas markets. The NGL market outlets includes our NGL pipeline system. The Permian Basin Gathering System includes twelve processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keystone, Tippet, Orla, Panther, Rebel, Grey Wolf and Arrowhead) with an aggregate processing capacity of 2.6 Bcf/d and one natural gas conditioning facility with an aggregate capacity of 200 MMcf/d.
•We own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of the joint venture.
•The Partnership previously owned a 50% membership interest in Ranch Westex JV LLC, which was sold in 2022.
Midcontinent Region:
•The Midcontinent Systems are located in three large natural gas producing regions in the United States: the Hugoton Basin in southwest Kansas, the Anadarko Basin in the Texas Panhandle and Oklahoma, including the STACK and SCOOP plays, and the Arkoma Basin in Eastern Oklahoma and Arkansas. These mature basins have continued to provide generally long-lived, predictable production volumes. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include 24 natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Hamlin, Spearman, Crescent, Rose Valley, Hopeton, Bradley, Bradley II, McClure, Wheeler, South Canadian, Clinton, Roger Mills, Canute, Cox City, Thomas, Calumet and Wetumka) with an aggregate capacity of approximately 3.1 Bcf/d.
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•We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
•We own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
•We own a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
•In September 2022, we acquired Woodford Express, LLC, which has cryogenic gas processing and treatment capacity of 450 MMcf/d and over 200 miles of gathering lines that are connected to Energy Transfer’s pipeline network.
Eastern Region:
•The Eastern Region assets are located in eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica Shales. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipelines, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.
•We also own a 51% membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
•We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, and which delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.
NGL and Refined Products Transportation and Services
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The following details the assets in our NGL and refined products transportation and services segment:
Description of AssetsMiles of Liquids PipelineNGL Fractionation / Processing Capacity
(MBbls/d)		Working Storage Capacity
(MBbls)
Liquids Pipelines:
Gulf Coast NGL Express900 — — 
West Texas Gateway510 — — 
Other Permian Basin NGL1,600 — — 
Mariner East680 — — 
Mariner West450 — — 
Mont Belvieu to Nederland270 
White Cliffs(1)
540 — — 
Other NGL600 — — 
Liquids Fractionation and Storage Facilities:
Mont Belvieu— 940 58,000 
Spindletop— — 8,000 
ET Geismar Olefins(2)
100 35 — 
Hattiesburg— — 5,200 
Cedar Bayou— — 1,600 
NGL Terminals:
Nederland— — 1,900 
Orbit Gulf Coast— — 1,200 
Marcus Hook— — 6,000 
Inkster— — 860 
Refined Products Pipelines:
Eastern region1,580 — — 
Midcontinent region440 — — 
Southwest region550 — — 
Inland600 — — 
JC Nolan Pipeline500 — — 
Refined Products Terminals:
Eagle Point— — 6,700 
Marcus Hook Terminal— — 930 
Marcus Hook Tank Farm— — 1,900 
Marketing Terminals— — 7,700 
JC Nolan Terminal— — 130 
(1)The White Cliffs Pipeline consists of Sunoco LP:two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Wholesale Subsidiaries(2)Additionally, the ET Geismar Olefins off-gas processing facility has inlet volume capacity of 54 MMcf/d.
Sunoco LLC,The following information describes our principal NGL and refined products transportation and services assets:
•Gulf Coast NGL Express is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelines, with throughput capacity of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
•West Texas Gateway transports mixed NGLs produced in the Permian Basin and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.
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•The Mariner East Pipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports NGLs from the Marcellus and Utica Shales in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware limited liability company,River, where they are processed, stored and distributed to local, domestic and waterborne markets.
•The Mont Belvieu to Nederland Pipeline System consists of three pipelines and delivers export-grade propane, butane and natural gasoline from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a total throughput capacity of approximately 530 MBbls/d. In addition, it includes an export-grade ethane pipeline utilized for our Orbit Gulf Coast joint venture as described below.
•The Mariner West pipeline provides transportation of ethane from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d.
•The White Cliffs NGL pipeline, in which we have 51% ownership interest, transports mixed NGLs produced in the DJ Basin to Cushing, Oklahoma where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90 MBbls/d.
•Other NGL pipelines include the 127-mile Justice pipeline, the 45-mile Freedom pipeline, the 20-mile Spirit pipeline and a 50% interest in the 87 mile Liberty pipeline.
•Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 58 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators. We have an additional 8 MMBbls of salt dome capacity at our Spindletop facility which we acquired in March 2022, and is located in Beaumont, Texas.
•Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Gulf Coast NGL Express, West Texas Gateway and Justice pipelines.
•ET Geismar Olefins consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
•The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-based cash flows.
•The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.
•The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs in connection with the Mont Belvieu to Nederland Pipeline System, which provides transportation of propane, butane and natural gasoline products from our Mont Belvieu, Texas storage and fractionation complex to the Nederland Terminal, where such products can be exported via ship.
•The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 200 MBbls/d, delivering from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas, as well as a 180 MBbls/d ethane refrigeration facility and 1.2 MMBbls of storage capacity.
•The Marcus Hook Terminal includes fractionation, terminalling and storage assets, with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground NGL refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Terminal currently serves as an off-take outlet for our Mariner East Pipeline System.
The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls. The terminal receives and delivers refined products via pipeline and primarily distributes motor fuel across 30 states throughoutprovides terminalling services to support movements on our refined products pipelines.
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•The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use the East Coast, Midwest, South CentralInkster terminal’s storage in connection with the Toledo North pipeline system and Southeast regionsfor the storage of the United States. Sunoco LLC also processes transmixNGLs from local producers and distributesa refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
•The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product through its terminalspipelines in Alabamaeastern, central and the Greater Dallas, Texas metroplex.
Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands.
Retail Subsidiaries
Susser Petroleum Property Company LLC, a Delaware limited liability company, primarily owns and leases convenience store properties.
Susser, a Delaware corporation, sells motor fuel and merchandisenorth central Pennsylvania, 8-inch refined products pipeline in Texas, New Mexico, and Oklahoma through Stripes-branded convenience stores.
Sunoco Retail, a Pennsylvania limited liability company, owns and operates convenience stores that sell motor fuel and merchandise primarily in Pennsylvania,western New York and Florida.various diameter refined products pipelines in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
MACS Retail•The midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan.
•The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products pipeline.
•The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio.
•The JC Nolan Pipeline, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 36 MBbls/d.
•We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.
•In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•The JC Nolan Terminal, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, provides diesel fuel storage in Midland, Texas.
•This segment also includes the following joint ventures: a 15% membership interest in Explorer, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur and Houston, Texas and extends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.
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Crude Oil Transportation and Services
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The following details our pipelines and terminals in its crude oil transportation and services operations:
Description of AssetsOwnership InterestMiles of Crude PipelineWorking Storage Capacity
(MBbls)
Dakota Access Pipeline36.40 %1,170 — 
Energy Transfer Crude Oil Pipeline36.40 %745 — 
Bayou Bridge Pipeline60 %210 — 
Permian Express Pipelines87.7 %1,760 — 
Wattenberg Oil Trunkline100 %75 360 
White Cliffs Pipeline(1)
51 %530 100 
Maurepas Pipeline51 %35 — 
Other Crude Oil Pipelines100 %6,790 — 
Nederland Terminal100 %— 31,000 
Fort Mifflin Terminal100 %— 3,300 
Eagle Point Terminal100 %— 1,800 
Midland Terminal100 %— 1,000 
Marcus Hook Terminal100 %— 1,000 
Houston Terminal100 %— 18,200 
Cushing Terminal100 %— 7,600 
Patoka, Illinois Terminal87.7 %— 1,900 
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(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:
Crude Oil Pipelines
Our crude oil pipelines consist of approximately 11,315 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including our wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, Mid-Valley and Wattenberg Oil Trunkline. Additionally, we have equity ownership interests in six crude oil pipelines. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a Virginia limited liability company, ownsnumber of refineries.
•Bakken Pipeline. TheDakota Access Pipeline and operates convenience storesEnergy Transfer Crude Oil Pipeline are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915-mile pipeline that transports domestically produced crude oil from the Bakken/Three Forks production areas in Virginia, Maryland,North Dakota to a storage and Tennessee.terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas. The Bakken Pipeline has a capacity of up to 750 MBbls/d. The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Aloha Petroleum, Ltd., a Hawaii corporation, ownsThe Dakota Access Pipeline consists of approximately 1,170 miles of 12, 20, 24 and operates convenience stores30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Hawaiian Islands.Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.
AsThe Energy Transfer Crude Oil Pipeline consists of Decemberapproximately 675 miles of mostly 30-inch converted natural gas pipeline and 70 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
•Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between Energy Transfer and a subsidiary of Phillips 66, in which we have a 60% ownership interest and serve as the operator of the pipeline. Phase I of the pipeline is a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, and Phase II of the pipeline, is a 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana.Bayou Bridge Pipeline has a capacity of approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
•Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview, Louisiana Access, Longview to Louisiana and Nederland Access pipelines. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, with origins in multiple locations in West Texas.
•White Cliffs Crude Pipeline. White Cliffs Pipeline owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
•Maurepas Pipeline. The Maurepas Pipeline consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.
•Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma and Kansas. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma and Kansas systems to Cushing, Oklahoma. We are one of the
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largest purchasers of crude oil from producers in the area and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
We also own crude oil and condensate gathering assets in the Anadarko Basin and the Williston Basin. The Anadarko Basin assets were designed and built to serve the crude oil and condensate production in the SCOOP and STACK plays. A portion of these operations are conducted through Enable South Central Pipeline, a joint venture with a subsidiary of CVR Energy, Inc., which is operated by us and in which we own a 60% membership interest. The Williston Basin crude oil and produced water gathering assets were designed and built to receive crude oil on pipelines near our customers’ wells for delivery to third-party transportation pipelines, and produced water gathering pipelines for delivery to third-party disposal wells.
Crude Oil Terminals
•Nederland. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately 31 2017,MMBbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland Terminal can receive crude oil at three of its six ship docks and three of its four barge berths. The three ship docks are capable of receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls. The terminal also has crude oil rail unloading facilities, including steam availability for heating heavy oils prior to loading.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the closingterminal is capable of delivering over 2 MMBbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
•Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks. The Darby Creek tank farm is a primary crude oil storage terminal that receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines and has a total storage capacity of approximately 2.7 MMBbls.
•Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1.8 MMBbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•Midland. The Midland terminal is located in Midland, Texas and includes approximately 1 MMBbls of crude oil storage, a combined 20 lanes of truck loading and unloading, and provides access to the Permian Express 2 pipeline.
•Marcus Hook. The Marcus Hook Terminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 MMBbls.
•Patoka, Illinois. The Patoka, Illinois terminal is a tank farm owned by the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 1.9 MMBbls of crude oil storage.
•Houston. The Houston Terminal consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.
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•Cushing. The Cushing Terminal has approximately 7.6 MMBbls of crude oil storage, of which 5.6 MMBbls are leased to customers and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately 1,348 convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sitesmajor storage terminals in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LPCushing. The Cushing terminal also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.includes truck unloading facilities.
As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.
As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.
Investment in Lake Charles LNG
Regasification Facility
Lake Charles LNG, aour wholly-owned subsidiary, of ETE, owns aan LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/day.d.

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Liquefaction Project
LCL, an entity owned 60% by ETE and 40% by ETP,Lake Charles LNG Export, our wholly-owned subsidiary, is in the process of developing thea natural gas liquefaction project in conjunction with BG pursuant to a project development agreement entered into in September 2013 and scheduled to expire at the endsite of February 2017, subject to the parties’ right to mutually extend the term. Pursuant to this agreement, each of LCLour Lake Charles LNG import terminal and BG are obligated to pay 50% of the development expenses for the liquefactionregasification facility. The project subject to reimbursement by the other party if such party withdraws from the project prior to both parties making an affirmative FID to become irrevocably obligated to fully develop the project, subject to certain exceptions. The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gaswould utilize existing dock 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 arestorage facilities owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease fromlocated on the Lake Charles Harborsite. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March 2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. The project as currently designed is fully permitted by federal, state and Terminal District.
The liquefaction project is expectedlocal authorities, has all necessary export licenses and benefits from the infrastructure related to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and is obligated to pay reservation fees for 100%other assets.
Since the beginning of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by2022, Lake Charles LNG Export has executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year LNG agreement with Shell NA LNG LLC. We have also signed nonbinding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the remaining acres areproject. Upon completion of the LNG project, we expect to be leased by LCL under a long-term leaserealize significant incremental cash flows from thetransportation of natural gas on our Trunkline pipeline system, and other Energy Transfer pipelines upstream from Lake Charles Harbor and Terminal District.Charles.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL.Lake Charles LNG Export. In March 2013, LCLLake Charles LNG Export obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCLLake Charles LNG Export 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”). In October 2020, the DOE extended the FTA Authorization and Non-FTA Authorization to 30- and 25-year terms, respectively, following first deliveries on or before December 2025, consistent with the FERC authorization for the project. The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. 
respectively, commencing with the completion of construction of the liquefaction facility. In addition, We haveLake Charles LNG Export received ourits wetlands permits from the United States Army Corps of Engineers (“USACE”)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.
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Midstream
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The following details our assets in the midstream segment:
Description of AssetsNet Gas Processing Capacity
(MMcf/d)
South Texas2,430 
Ark-La-Tex1,990 
North Central Texas700 
Permian2,815 
Midcontinent3,585 
Eastern200 
The following information describes our principal midstream assets:
South Texas Region:
•Our South Texas assets, which include the Southeast Texas System and the Eagle Ford System, are an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford Shale.
The assets in our Southeast Texas System include a large natural gas gathering system that covers thirteen counties between Austin and Houston, Texas and connects to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. This system also includes three natural gas processing plants (La Grange, Alamo and Brookeland) with an aggregate capacity of 510 MMcf/d. These plants process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines.
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Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The assets in our Eagle Ford System consist of 30-inch and 42-inch natural gas gathering pipelines originating in Dimmitt County, Texas, and extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. These assets also include four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with an aggregate capacity of 1.9 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines.
•We own a 60% interest in Edward Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities, and an oil pipeline and oil stabilization facility in South Texas.
Ark-La-Tex Region:
•Our Ark-La-Tex assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, Tristate, Logansport, Magnolia, Olympia, Amoruso, and Lumberjack systems, which collectively include eleven natural gas treating facilities, with aggregate capacity of 3.0 Bcf/d.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that connects to a third party that provides access to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the fourteen natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Lincoln, Rosewood, Mt. Olive, Panola, Sligo and Waskom) have an aggregate capacity of 2.0 Bcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
•The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. Our North Central Texas assets include our Godley plant, which processes rich gas produced from the Barnett Shale and STACK play, with an aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
•The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the midcontinent region of the United States and Texas natural gas markets. The NGL market outlets includes our NGL pipeline system. The Permian Basin Gathering System includes twelve processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keystone, Tippet, Orla, Panther, Rebel, Grey Wolf and Arrowhead) with an aggregate processing capacity of 2.6 Bcf/d and one natural gas conditioning facility with an aggregate capacity of 200 MMcf/d.
•We own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of the joint venture.
•The Partnership previously owned a 50% membership interest in Ranch Westex JV LLC, which was sold in 2022.
Midcontinent Region:
•The Midcontinent Systems are located in three large natural gas producing regions in the United States: the Hugoton Basin in southwest Kansas, the Anadarko Basin in the Texas Panhandle and Oklahoma, including the STACK and SCOOP plays, and the Arkoma Basin in Eastern Oklahoma and Arkansas. These mature basins have continued to provide generally long-lived, predictable production volumes. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include 24 natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Hamlin, Spearman, Crescent, Rose Valley, Hopeton, Bradley, Bradley II, McClure, Wheeler, South Canadian, Clinton, Roger Mills, Canute, Cox City, Thomas, Calumet and Wetumka) with an aggregate capacity of approximately 3.1 Bcf/d.
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•We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
•We own the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
•We own a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
•In September 2022, we acquired Woodford Express, LLC, which has cryogenic gas processing and treatment capacity of 450 MMcf/d and over 200 miles of gathering lines that are connected to Energy Transfer’s pipeline network.
Eastern Region:
•The Eastern Region assets are located in eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica Shales. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipelines, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.
•We also own a 51% membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
•We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, and which delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.
NGL and Refined Products Transportation and Services
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The following details the assets in our NGL and refined products transportation and services segment:
Description of AssetsMiles of Liquids PipelineNGL Fractionation / Processing Capacity
(MBbls/d)		Working Storage Capacity
(MBbls)
Liquids Pipelines:
Gulf Coast NGL Express900 — — 
West Texas Gateway510 — — 
Other Permian Basin NGL1,600 — — 
Mariner East680 — — 
Mariner West450 — — 
Mont Belvieu to Nederland270 
White Cliffs(1)
540 — — 
Other NGL600 — — 
Liquids Fractionation and Storage Facilities:
Mont Belvieu— 940 58,000 
Spindletop— — 8,000 
ET Geismar Olefins(2)
100 35 — 
Hattiesburg— — 5,200 
Cedar Bayou— — 1,600 
NGL Terminals:
Nederland— — 1,900 
Orbit Gulf Coast— — 1,200 
Marcus Hook— — 6,000 
Inkster— — 860 
Refined Products Pipelines:
Eastern region1,580 — — 
Midcontinent region440 — — 
Southwest region550 — — 
Inland600 — — 
JC Nolan Pipeline500 — — 
Refined Products Terminals:
Eagle Point— — 6,700 
Marcus Hook Terminal— — 930 
Marcus Hook Tank Farm— — 1,900 
Marketing Terminals— — 7,700 
JC Nolan Terminal— — 130 
(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
(2)Additionally, the ET Geismar Olefins off-gas processing facility has inlet volume capacity of 54 MMcf/d.
The following information describes our principal NGL and refined products transportation and services assets:
•Gulf Coast NGL Express is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelines, with throughput capacity of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
•West Texas Gateway transports mixed NGLs produced in the Permian Basin and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.
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•The Mariner East Pipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports NGLs from the Marcellus and Utica Shales in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets.
•The Mont Belvieu to Nederland Pipeline System consists of three pipelines and delivers export-grade propane, butane and natural gasoline from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a total throughput capacity of approximately 530 MBbls/d. In addition, it includes an export-grade ethane pipeline utilized for our Orbit Gulf Coast joint venture as described below.
•The Mariner West pipeline provides transportation of ethane from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d.
•The White Cliffs NGL pipeline, in which we have 51% ownership interest, transports mixed NGLs produced in the DJ Basin to Cushing, Oklahoma where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90 MBbls/d.
•Other NGL pipelines include the 127-mile Justice pipeline, the 45-mile Freedom pipeline, the 20-mile Spirit pipeline and a 50% interest in the 87 mile Liberty pipeline.
•Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 58 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators. We have an additional 8 MMBbls of salt dome capacity at our Spindletop facility which we acquired in March 2022, and is located in Beaumont, Texas.
•Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Gulf Coast NGL Express, West Texas Gateway and Justice pipelines.
•ET Geismar Olefins consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
•The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-based cash flows.
•The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.
•The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs in connection with the Mont Belvieu to Nederland Pipeline System, which provides transportation of propane, butane and natural gasoline products from our Mont Belvieu, Texas storage and fractionation complex to the Nederland Terminal, where such products can be exported via ship.
•The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 200 MBbls/d, delivering from our Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas, as well as a 180 MBbls/d ethane refrigeration facility and 1.2 MMBbls of storage capacity.
•The Marcus Hook Terminal includes fractionation, terminalling and storage assets, with a capacity of approximately 2 MMBbls of NGL storage capacity in underground caverns, 4 MMBbls of above-ground NGL refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Terminal currently serves as an off-take outlet for our Mariner East Pipeline System.
The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.
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•The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use the Inkster terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
•The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product pipelines in eastern, central and north central Pennsylvania, 8-inch refined products pipeline in western New York and various diameter refined products pipelines in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
•The midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch refined products pipeline in Michigan.
•The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products pipeline.
•The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of Ohio.
•The JC Nolan Pipeline, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 36 MBbls/d.
•We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.
•In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•The JC Nolan Terminal, a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, provides diesel fuel storage in Midland, Texas.
•This segment also includes the following joint ventures: a 15% membership interest in Explorer, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur and Houston, Texas and extends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.
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Crude Oil Transportation and Services
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The following details our pipelines and terminals in its crude oil transportation and services operations:
Description of AssetsOwnership InterestMiles of Crude PipelineWorking Storage Capacity
(MBbls)
Dakota Access Pipeline36.40 %1,170 — 
Energy Transfer Crude Oil Pipeline36.40 %745 — 
Bayou Bridge Pipeline60 %210 — 
Permian Express Pipelines87.7 %1,760 — 
Wattenberg Oil Trunkline100 %75 360 
White Cliffs Pipeline(1)
51 %530 100 
Maurepas Pipeline51 %35 — 
Other Crude Oil Pipelines100 %6,790 — 
Nederland Terminal100 %— 31,000 
Fort Mifflin Terminal100 %— 3,300 
Eagle Point Terminal100 %— 1,800 
Midland Terminal100 %— 1,000 
Marcus Hook Terminal100 %— 1,000 
Houston Terminal100 %— 18,200 
Cushing Terminal100 %— 7,600 
Patoka, Illinois Terminal87.7 %— 1,900 
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(1)The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:
Crude Oil Pipelines
Our crude oil pipelines consist of approximately 11,315 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including our wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, Mid-Valley and Wattenberg Oil Trunkline. Additionally, we have equity ownership interests in six crude oil pipelines. Our crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
•Bakken Pipeline. TheDakota Access Pipeline and Energy Transfer Crude Oil Pipeline are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915-mile pipeline that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas. The Bakken Pipeline has a capacity of up to 750 MBbls/d. The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
The Dakota Access Pipeline consists of approximately 1,170 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.
The Energy Transfer Crude Oil Pipeline consists of approximately 675 miles of mostly 30-inch converted natural gas pipeline and 70 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
•Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between Energy Transfer and a subsidiary of Phillips 66, in which we have a 60% ownership interest and serve as the operator of the pipeline. Phase I of the pipeline is a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, and Phase II of the pipeline, is a 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana.Bayou Bridge Pipeline has a capacity of approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
•Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2, Permian Express 3, Permian Express 4, Permian Longview, Louisiana Access, Longview to Louisiana and Nederland Access pipelines. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, with origins in multiple locations in West Texas.
•White Cliffs Crude Pipeline. White Cliffs Pipeline owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
•Maurepas Pipeline. The Maurepas Pipeline consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.
•Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma and Kansas. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma and Kansas systems to Cushing, Oklahoma. We are one of the
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largest purchasers of crude oil from producers in the area and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
We also own crude oil and condensate gathering assets in the Anadarko Basin and the Williston Basin. The Anadarko Basin assets were designed and built to serve the crude oil and condensate production in the SCOOP and STACK plays. A portion of these operations are conducted through Enable South Central Pipeline, a joint venture with a subsidiary of CVR Energy, Inc., which is operated by us and in which we own a 60% membership interest. The Williston Basin crude oil and produced water gathering assets were designed and built to receive crude oil on pipelines near our customers’ wells for delivery to third-party transportation pipelines, and produced water gathering pipelines for delivery to third-party disposal wells.
Crude Oil Terminals
•Nederland. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately 31 MMBbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland Terminal can receive crude oil at three of its six ship docks and three of its four barge berths. The three ship docks are capable of receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls. The terminal also has crude oil rail unloading facilities, including steam availability for heating heavy oils prior to loading.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 MMBbls/d of crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
•Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks. The Darby Creek tank farm is a primary crude oil storage terminal that receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines and has a total storage capacity of approximately 2.7 MMBbls.
•Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1.8 MMBbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
•Midland. The Midland terminal is located in Midland, Texas and includes approximately 1 MMBbls of crude oil storage, a combined 20 lanes of truck loading and unloading, and provides access to the Permian Express 2 pipeline.
•Marcus Hook. The Marcus Hook Terminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 MMBbls.
•Patoka, Illinois. The Patoka, Illinois terminal is a tank farm owned by the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 1.9 MMBbls of crude oil storage.
•Houston. The Houston Terminal consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.
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•Cushing. The Cushing Terminal has approximately 7.6 MMBbls of crude oil storage, of which 5.6 MMBbls are leased to customers and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.
Crude Oil Acquisition and Marketing
Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 363 crude oil transport trucks, 350 trailers and approximately 166 crude oil truck unloading facilities, as well as third-party truck, rail, pipeline and marine assets.
Investment in Sunoco LP
Sunoco LP’s fuel distribution and marketing operations are conducted by the following consolidated subsidiaries:
•    Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in more than 40 states and territories throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama, Arkansas, Florida, Indiana, Illinois, Maryland, New Jersey, New York, Texas and Virginia;
•    Sunoco Retail LLC (formerly Sunoco Property Company LLC) (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey and distributes motor fuel in Puerto Rico. Sunoco Retail also leases owned sites to commissioned agents who sell motor fuels to the motoring public on Sunoco Retail’s behalf for a commission;
•    Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands; and
•Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands and leases owned sites to commission agents who sell motor fuels on Aloha’s behalf for a commission.
Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes it throughout the East Coast, Midwest, South Central and Southeast regions of the United States, as well as Hawaii to:
•76 company owned and operated retail stores;
•504 independently operated commission agent locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;
•6,897 retail stores operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and
•approximately 1,800 other commercial customers, including unbranded retail stores, other fuel distributors, school districts and municipalities and other industrial customers.
Sunoco LP’s operations also include retail operations in Hawaii and New Jersey, credit card services and franchise royalties.
Investment in USAC
The following details the assets of USAC:
USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 87.1% of its total fleet horsepower as of December 31, 2022. The remainder of its fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.
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The following table provides a summary of USAC’s compression units by horsepower as of December 31, 2022:
Unit HorsepowerFleet HorsepowerNumber of UnitsHorsepower on Order (1)Number of Units on OrderTotal HorsepowerNumber of UnitsPercent of Fleet HorsepowerPercent of Units
Small horsepower
<400502,012 2,956 — — 502,012 2,956 12.9 %54.2 %
Large horsepower
>400 and <1,000428,947 732 — — 428,947 732 11.1 %13.4 %
>1,0002,785,895 1,698 165,000 66 2,950,895 1,764 76.0 %32.4 %
Total large horsepower3,214,842 2,430 165,000 66 3,379,842 2,496 87.1 %45.8 %
Total horsepower3,716,854 5,386 165,000 66 3,881,854 5,452 100.0 %100.0 %
(1)As of December 31, 2022, USAC had 66 large horsepower units, consisting of 165,000 horsepower, on order for delivery during 2023.
All Other
The following details the significant assets in the “All Other” segment.
Compression
We own Dual Drive Technologies, Ltd, which provides compression services to customers engaged in the transportation of natural gas, including our other segments.
Natural Resources Operations
Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2022, we owned or controlled approximately 733 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
Canadian Operations
In August 2022, we completed the sale of our 51% ownership interest in Energy Transfer Canada, which owns processing and gathering facilities in Alberta, Canada.
Business Strategy
We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through strategic acquisitions, internally generated expansion, measures aimed at increasing the profitability of our existing assets and executing cost control measures where appropriate to manage our operations.
We intend to continue to operate as a diversified, growth-oriented limited partnership. We believe that by pursuing independent operating and growth strategies we will be best positioned to achieve our objectives. We balance our desire for growth with our goal of preserving a strong balance sheet, ample liquidity and investment grade credit metrics.
Following is a summary of the business strategies of our core businesses:
Growth through acquisitions. We intend to continue to make strategic acquisitions that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing assets while supporting our investment grade credit ratings.
Engage in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream and transportation services.
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Increase cash flow from fee-based businesses. We intend to increase the percentage of our business conducted with third parties under fee-based arrangements in order to provide for stable, consistent cash flows over long contract periods while reducing exposure to changes in commodity prices.
Enhance profitability of existing assets. We intend to increase the profitability of our existing asset base by adding new volumes under long-term producer commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.
Competition
Natural Gas
The business of providing natural gas gathering, compression, treating, transporting, storingtransportation, storage and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage operationssegment are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.
We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil and gas companies, interstate and intrastate pipelines and other companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

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

changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
Natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. The discovery and development of new shale formations across the United States has created an abundance of natural gas and crude oil resulting in a negative impact on prices in recent years for natural gas and crude oil. As a result, some of our exploration and production customers have been adversely impacted; however, we are monitoring these customers and mitigating credit risk as necessary.
During the year ended December 31, 2017,2022, none of our customers individually accounted for more than 10% of our consolidated revenues.
Regulation
Regulation of Interstate Natural Gas Pipelines.The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”),NGA, the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Florida Gas Transmission,FGT, Transwestern, Panhandle, Eastern, Trunkline, Gas, Tiger, Fayetteville Express, Rover, Sea Robin, Gulf States and Midcontinent Express, pipelinesEGT, MRT, SESH, Stingray and Southwest Gas transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.
The FERC’s NGA authority includes the power to:
•approve the siting, construction and operation of new facilities;
•review and approve transportation rates;
•determine the types of services our regulated assets are permitted to perform;
•regulate the terms and conditions associated with these services;
•permit the extension or abandonment of services and facilities;
•require the maintenance of accounts and records; and
•authorize the acquisition and disposition of facilities.
Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
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The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate available to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint or on the FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.

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

to assess or seek civil penalties of up to approximately $1$1.5 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Failure to comply with the NGA, the Energy Policy Act of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.
Regulation of Intrastate Natural Gas and NGL Pipelines.  Pipelines.Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”).NGPA. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on theour pipeline systems of Enable Oklahoma Intrastate Transmission, LLC, Oasis pipeline, HPL System, East Texas pipeline, ETPipeline, LP, Houston Pipe Line Company LP, ETC Katy Pipeline, LLC, Energy Transfer Fuel, System,LP, , Lobo Pipeline Company, LLC, Pelico Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail Pipeline, LLC are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
Our NGL pipelines and operations may also be or becomeare subject to state public utility or related jurisdictionstatutes and regulations which could impose additional environmental, safety and operational regulationsrequirements relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities.transportation systems. In some jurisdictions, state public utility commission oversight may include the possibility of fines, penalties and delays in construction related to these regulations. In addition, the rates, terms and conditions of service for shipments of NGLs on our pipelines are subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign
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commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Sales of Natural Gas and NGLs.The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.
To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposingfrequently proposes and implementingimplements new rules and regulations affecting those operationssegments of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.
Regulation of Gathering Pipelines.  Pipelines.Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject

of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.
Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.
We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates
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for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies and precedents.
For many locations served by our product and crude pipelines, we are able to establish negotiated rates. Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In 2005,July 2016, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in United Airlines, Inc., et al. v. FERC, issuedfinding that the FERC had failed to demonstrate that permitting an interstate petroleum products pipeline organized as a policy statement stating that it would permit common carriers, among others,master limited partnership, or MLP, to include an income tax allowance in cost-of-servicethe cost of service underlying its rates, in addition to reflect actual or potential tax liability attributablethe discounted cash flow return on equity, would not result in the pipeline partnership owners double recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a regulated entity’s operating income, regardlessresult of the formincome tax allowance.
In March 2018, the FERC issued a Revised Policy Statement on Treatment of ownership. Under FERC’s policy, a tax pass-through entity seeking suchIncome Taxes in which the FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance must establish that its partners or members have an actual or potential income tax liabilityand a return on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carriers that are organized as pass-through entities, it still entails rate risk dueequity pursuant to the FERC’s case-by-case review approach.discounted cash flow methodology. The FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC stated it will address the application of this policy,the United Airlines decision to non-MLP partnership forms as well as any decision by

those issues arise in subsequent proceedings. In July 2018, the FERC regarding our costdismissed requests for rehearing and clarification of service, may alsothe March 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be subjectprecluded in a future proceeding from arguing and providing evidentiary support that it is entitled to review in the courts. In December 2016, FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. FERC requested comments regarding how to address any double recovery resulting from the Commission’s currentan income tax allowance and ratedemonstrating that its recovery of return policies. The comment period with respect toan income tax allowance does not result in a double recovery of investors’ income tax costs. On July 31, 2020, the noticeUnited States Court of inquiry endedAppeals for the District of Columbia Circuit issued an opinion upholding FERC’s March 2018 Revised Policy Statement, as clarified and revised on April 7, 2017. The outcomerehearing. In light of the inquiry is still pending.
Finally,rehearing order’s clarification regarding individual entities’ ability to argue in November 2017 FERC respondedsupport of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a petition for declaratory order and issued an order thatmaster limited partnership, the impacts the FERC’s policy on the treatment of income taxes may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated withrates an interstate pipeline held in a tax-pass-through entity can pricecharge for the FERC regulated transportation services are unknown at this time. Please see “Item 1A. Risk Factors - Regulatory Matters.”
Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. With the lower tax rate, and as discussed immediately above, the maximum tariff rates allowed by the FERC under its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangementsrate base methodology may be impacted by a marketing affiliate if: (i)lower income tax allowance component. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the transportation differential applicableconstruction of the pipelines, and the rate base methodology does not apply directly to its affiliate’s interstate pipeline transportation service  is atthese contracts. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. In addition, several of these pipelines are covered by approved settlements, pursuant to the affiliated pipeline’s filedwhich rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or,filings will be made in the alternative, grant rehearingfuture. As such, the timing and impact to these systems of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impactany tax-related policy change is unknown at this time and varies based on the rates we are permitted to charge.circumstances of each pipeline.
The EPAct of 1992 required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, the FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPIFG.PPI-FG. The FERC’s indexing methodology is subject to review every five years. During
In December 2020, FERC issued an order setting the indexed rate at PPI-FG plus 0.78% during the five-year period commencing July 1, 20112021 and ending June 30, 2016, common carriers2026. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their
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indexed ceilings annually by PPIFG plus 2.65%PPI-FG minus 0.21%. BeginningFERC directed liquids pipelines to recompute their ceiling levels for July 1, 2016,2021 through June 30, 2022, as well as the indexing method providedceiling levels for annual changes equalthe period July 1, 2022 through June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the change in PPIFG plus 1.23%.rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior 2 years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules ended on March 17, 2017. FERC has taken no further action on the proposed rule to date.
Finally, inIn November 2017, the FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline. In particular, the FERC’s November 2017 order prohibits buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss. Several parties have requested that the FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order. WeThe FERC denied requests for rehearing of the November 17 order on December 15, 2022.
Finally, on December 15, 2022, the FERC issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service, which addresses whether a contract for committed transportation service complies with the Interstate Commerce Act where the only shipper to obtain the committed service is an affiliate of the regulated entity. If adopted, the proposed policy statement would create a rebuttable presumption that affiliate contracts are unableunduly discriminatory and not just and reasonable in certain circumstances and require a pipeline to predict howproduce additional evidentiary support for affiliate contracts rates and terms. This follows a trend of increased scrutiny by FERC will respond to such requests.  Depending on how FERC responds, it could have an impactaffiliated contracts across all industries regulated by the FERC. Initial comments on the rates weproposed policy statement are permitted to charge.due on February 13, 2023.
Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the PA PUC,Pennsylvania Public Utility Commission and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by the FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Pipeline Safety.Our pipeline operations are subject to regulation by the DOT, through the PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA,

as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas, (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.
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The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”).2016. The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000$0.1 million to $200,000$0.2 million for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. Effective April 27, 2017, to account for inflation,In May 2021, PHMSA issued a final rule increasing those maximum civil penalties were increased to $209,002approximately $0.2 million per day, with a maximum of $2,090,022approximately $2 million for a series of violations.violations, to account for inflation. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking. To that end, in November 2021, PHMSA issued a final rule significantly expanding reporting and safety requirements of operators of gas gathering pipelines. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019 and,rule imposes safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, requiringwill impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Additionally, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to complete certainupdate their inspection and maintenance plans for the elimination of its outstanding mandates under the 2011 Pipeline Safety Acthazardous leaks and developing new safety standards forminimization of natural gas storage facilities by June 22, 2018. The 2016 Act also empowersfrom related pipeline facilities. PHMSA, together with state regulators, are expected to address imminent hazards by imposing emergency restrictions, prohibitionscommence and safety measures on owners and operatorscomplete inspection of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulationsthese plans 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.2022.
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” underHowever, in October 2019, PHMSA published two further final rules, in addition to the NGPSA presently exempts substantial portions of our gathering facilities located outside of cities, townsNovember 2021 rule discussed above, that create or any area designated as residential or commercial from jurisdiction under the NGPSA, but does not applyexpand reporting, inspection, maintenance, and other pipeline safety obligations, including, among other things, extending pipeline integrity assessments to our intrastate naturalpipelines in certain locations, including newly-defined “Moderate Consequence Areas” (“MCAs”). Specifically, PHMSA issued a final rule imposing numerous requirements on onshore gas pipelines. In recent years, the PHMSA has considered changes to this rural gathering exemption, including publishing an advance notice of proposed rulemakingtransmission pipelines relating to gas pipelinesmaximum allowable operating pressure (“MAOP”), reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in 2011, in which the agency sought public comment on possible changes to the definition of “high consequence areas”MCAs, non-High Consequence Area (“HCAs”), and “gathering lines”Class 3 and Class 4 areas by 2023, and the strengtheningconsideration of seismicity as a risk factor in integrity management. Establishing MAOP through reliance on historical pipeline design, construction, inspection, testing, and other records requires that such records be traceable, verifiable, and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. PHMSA’s second final rule, published in October 2019, applicable to hazardous liquid transmission and gathering pipelines, significantly extended and expanded the reach of certain integrity management requirements. In April 2016, pursuantrequirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to onepermit such use), increased annual, accident, and safety-related conditional reporting requirements, and expanded use of theleak detection systems beyond HCAs. The integrity-related requirements and other provisions of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that, among other things, would expand certainthe 2016 Pipeline Safety Act, and the PIPES Act of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain2020, as fewwell as 5 dwellings within a potential impact area; require natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking.
In January 2017, PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines. The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015. The general effective date of this final rule is six months from publication in the Federal Register, but it is currently subject to further administrative review in connection with the transition of Presidential administrations and thus,any implementation of this final rule remains uncertain. The final rule addresses several areas including reporting requirements for gravityPHMSA rules thereunder, could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis and unregulated gathering lines, inspections after weather or climatic events, leak detection system requirements, revisions to repair criteria and other integrity management revisions. In addition, PHMSA issued regulations on January 23, 2017, on operator qualification, cost recovery, accident and incident notification and other pipeline safety changesincur increased operating costs that are now effective. These regulations are also subject, however, to potential further review in connection with the transition of Presidential

administrations. Historically, our pipeline safety costscould 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.financial condition.
In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the Texas Railroad Commission,TRRC, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements,
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which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Environmental Matters
General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent U.S. federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Similar or more stringent laws also exist in Canada. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities.
We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain however, that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.
Uncertainty about the future course of regulation continues to exist following the change in U.S. presidential administrations in January 2021. Upon taking office, the Biden Administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, several regulatory developments have occurred, but it remains unclear the degree to which this will continue. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group has not yet published its final recommendations. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.
Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.
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We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial

portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, followingin 2016, the filing of a lawsuit by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the United States District Court for the District of Columbia on December 28, 2016. Under the decree, the EPA is requiredwith several environmental groups to propose no later than March 15, 2019, a rulemaking for revision ofanalyze certain Subtitle D criteria regulations pertaining to oil and gas wastes or signand, if necessary, revise them. In response to the decree, in April 2019, the EPA signed 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.necessary at this time. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.
We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and refined products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.
As of December 31, 20172022 and 2016,2021, accruals of $372$282 million and $344$293 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities including, for example, certain matters assumed in connection with our acquisition of the HPL System, our acquisition of Transwestern, potential environmental liabilities for three sites that were formerly owned by Titan Energy Partners, L.P. or its predecessors, and the predecessor owner’s share of certain environmental liabilities of ETC OLP.liabilities.
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.’sETC Sunoco’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $284$219 million and $289$234 million at December 31, 20172022 and 2016,2021, respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by ETC Sunoco, Inc., closed and/or sold refineries and other formerly owned sites. In December 2013,We have established 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, 20172022, the captive insurance company held $207$145 million of cash and investments.
The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete

areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or
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mitigation of off-site migration. A change in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.
In general, a remediation site or issue is typically evaluated on an individual basis based upon information available for the site or issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows us the minimum amount of the range to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded.
In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (that is, it is less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2017, the aggregate of such additional estimated maximum reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million, which amount is in excess of the $372 The Partnership’s consolidated balance sheet reflected $282 million in environmental accruals recorded onas of December 31, 2017. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets, and in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.2022.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $5$3 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows, but management can provide no assurance.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering

the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue completed attainment/non-attainment designations in 2018, and states with moderate or high non-attainment areas must submit state implementation plans to the EPA by October 2021. By law, the EPA must review each NAAQS every five years. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. However, the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018.Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this or other new regulations could, among
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other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.
Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In May 2015, the EPA issued a final rule that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the United States Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In June 2015, the EPA and the United States Army Corps of Engineers (the “Corps”)USACE published a final rule attempting to clarify the federal jurisdictional reach over waters“waters of the United States,States” (“WOTUS”), but legal challenges to this rule followed. The 2015In January 2020, a new “waters of the United States” rule was stayed nationwidefinalized to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the United States Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repealreplace the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction,following four categories of waters as WOTUS: traditional navigable waters and territorial seas; perennial and intermittent tributaries to those waters; lakes, ponds and impoundments of jurisdictional waters; and wetlands adjacent to jurisdictional waters. However, both the 2015 and 2020 rulemakings have been subject to legal challenges, and the Biden Administration has announced plans to establish its own definition of WOTUS. Most recently, the EPA and USACE published a proposed rulemaking to revoke the 2020 rule in November 2017 specifying thatfavor of a pre-2015 definition until a new definition is proposed, which the contested May 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the United States Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. On January 31, 2018, the EPA and Corps finalized a rule that would delay applicability of the rule to two years from the rule’s publication in the Federal Register.Biden Administration has announced is underway. As a result of these recent developments, future implementationthe scope of jurisdiction under the June 2015 ruleClean Water Act is uncertain at this time, but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as our exploration and production customers’ drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
Additionally, for over 35 years, the USACE has authorized construction, maintenance, and repair of pipelines under a streamlined Nationwide Permit (“NWP”) program. From time to time, environmental groups have challenged the NWP program, and, in April 2020, the U.S. District Court for the District of Montana determined that NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects under the permit. In January 2021, the EPA and USACE issued a final rule reissuing and restricting NWP 12 to oil and gas pipelines and creating a new nationwide permit to authorize certain dredge and fill activities associated with utility lines conveying other substances such as brine, potable water, wastewater, and other substances excluding oil, natural gas, products derived from oil or natural gas, and electricity. The Biden Administration was asked to examine the final rule. Additionally, an October 2021 decision by the District Court for the Northern District of California resulted in the vacatur of a 2020 rule revising the Clean Water Act Section 401 certification process, following which, in November 2021, USACE announced that it has temporarily suspended finalization of certain permitting decisions, including under NWP 12, that rely on a Section 401 certification or waiver under the 2020 rule. While the full extent and impact of these vacaturs and any future revisions to NWP 12 by the Biden Administration is unclear at this time, we could face significant delays and financial costs if we must obtain individual permit coverage from USACE for our projects.
Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of oil. The PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill incident.
In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.
Endangered Species Act.Species. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers
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operate could cause our

customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.
Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs.greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. AtIn the federal level,United States, no comprehensive climate change legislation has been implemented at the federal level to date. TheHowever, Canada has implemented a federal carbon pricing regime, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in greenhouse gas emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. Additionally, the EPA has however, adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating GHG emissions, ofsuch as methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to attempts byIn September 2020, the EPA removed natural gas transmission and storage operations from this sector and rescinded the methane-specific requirements of the rule for production and processing facilities. However, Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for the crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission units or processes would have to stay portionscomply with specific standards of those standards,performance that may include leak detection using optical gas imaging and the agencysubsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. The EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in June 2017 to stay2022 that will contain proposed rule text, which was not included in the requirements for a period of two yearsNovember 2021 proposed rule, and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet publishedanticipates issuing a final rule and, as a result,by the June 2016 rule remains in effect but future implementationend of the 20162022. GHG emission standards, is uncertain at this time. This rule, should it remain in effect, and any other newincluding methane emission standardsemissions imposed on the oil and gas sector, could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally,Several states have also adopted, or are considering adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government.
At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiringin signing the “Paris Agreement,” a treaty that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHGsubmit individually-determined, non-binding emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed byAlthough the United States withdrew from the Paris Agreement under the Trump administration, President Biden recommitted the United States in February 2021, and, in April 2016 and entered into force2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered again in Glasgow in November 2016; however, this agreement does not create any binding obligations2021 at the 26th Conference to the Parties (“COP26”) during which multiple announcements were made, including a call for nationsparties to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017,eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States State Department informedand European Union jointly announced at COP26 the United Nationslaunch of the intentGlobal Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector.
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President Biden’s January 2021 climate change executive order directed the Secretary of the United StatesInterior to withdrawpause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. The executive order also directed the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherencefederal government to identify “fossil fuel subsidies” to take steps to ensure that, to the exit process and/orextent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. As noted above, a separate executive order issued in January 2021 established a Working Group that is called on to, among other things, develop methodologies for calculating the terms“social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.these estimates. The Working Group has not yet published its final recommendations.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Recently, activistsLitigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers. Various investors are becoming increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing for fossil fuel energy companies also have directed their attention atbecome more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil-fuelfossil fuel energy companies, which hascompanies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in certainover $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions fundswill be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and other sources of capital restricting or eliminating their investment in oilpotential solutions for the climate-related challenges most relevant to central banks and natural gas activities. Ultimately, thissupervisory authorities. Such efforts could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related toactivities and could also increase the cost of obtaining financings and/or negatively affect terms of financings.
Finally, climatic events in the areas in which we operate, whether from climate change the International Energy Agency estimates that global energy demand will continueor otherwise, can cause disruptions and, in some cases, delays in, or suspension of, our services. These events, including but not limited to risedrought, winter storms, wildfire, extreme temperatures or flooding, may become more intense or more frequent as a result of climate change and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods.continued operations. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities or our customers’ facilities from powerful winds or rising waters, or increased costs for, or difficulty obtaining, 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.transport, and thus demand for our services. 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.
We recognize the need to decrease emissions and integrate alternative energy sources into our operations, and we actively pursue economically beneficial opportunities to reduce our environmental footprint throughout our operations. Protecting public health and the environment is the primary initiative of our environmental management teams, both in the construction and operation of our assets. These teams have worked to reduce our emissions and minimize our environmental impact. Some examples of our teams’ efforts include:
•in our natural gas compression business, the use of our patented dual-drive technology, which offers the ability to switch compression drivers between an electric motor and a natural gas engine, allowed us to reduce our emissions of nitrogen oxide, carbon monoxide, CO2 and VOCs;
•the installation of approximately 12,000 low-emission pneumatic devices throughout our pipeline systems has allowed us to safely and efficiently adjust and control our operations and reduce methane emissions;
•the voluntary installation of thermal oxidizers, which destroy VOCs and convert methane to CO2 (a less carbon-intense GHG), thereby reducing VOC and methane emissions by 98 percent or more at many of our more than 50 natural gas processing and sweetening plants;
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•the implementation of an innovative liquids management process throughout much of our natural gas gathering pipeline system has allowed us to minimize flash emissions and methane emissions;
•the use of optical gas imaging cameras at our more than 2,200 gas gathering and processing facilities as part of our leak detection and repair program allow us to reduce emissions, improve safety, reduce costs, prevent product loss, and maintain equipment integrity;
•the use of in-line inspection tools, or smart pigs, allow us to detect corrosion, cracks or other defects along our pipeline systems thereby protecting the environment and the safety of our communities, employees and landowners; and
•the use of other methods, including pipeline blowdown direct injection, liquids pipeline system optimization, crude oil truck unloading and direct injection, all of which help to reduce emissions and the release of methane into the atmosphere across our operations.
Powering our assets through renewable energy sources is an established part of our operations where it is economically viable to do so. We have reduced our carbon footprint by using a diversified mix of energy sources, including solar and wind power to generate electrical power. The percentage of electrical energy we purchase on a given day originating from solar and wind sources is approaching 20 percent. Since 2019, we have entered into dedicated solar contracts to purchase 148 megawatts of solar power to support the operations of our assets. We also operate approximately 18,000 solar panel-powered metering stations across the United States.
In February 2021, we announced the formation of our alternative energy group. This group is tasked with increasing our efforts to support renewable energy projects such as solar and/or wind farms, either as a power purchaser, or in a partnership with third party developers, when they make economic sense. This group is also focused on developing alternative energy projects aimed at reducing the environmental footprint throughout our operations, including a variety of projects related to carbon capture, utilization and sequestration of CO2.
While our environmental management initiatives have not materially impacted our capital expenditures or results of operations, we recognize that the non-financial impacts of these initiatives are of interest to our investors and other stakeholders. We voluntarily publish additional information on those initiatives; however, much of that separately published information is excluded from this annual report on Form 10-K if it is not material in the context of the consolidated Partnership and/or if it is not required by the instructions to Form 10-K. For additional information on our environmental management initiatives, including our efforts to curb GHG emissions and to integrate alternative energy sources, please see our Corporate Responsibility Report available on our website at http://www.energytransfer.com/corporate-responsibility. Information contained on our website is not part of this report.
Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances, have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
EmployeesNatural Resource Reviews. The National Environmental Policy Act (“NEPA”) provides for an environmental impact assessment process in connection with certain projects that involve federal lands or require approvals by federal agencies. The NEPA process implicates a number of other environmental laws and regulations, including the Endangered Species Act, Migratory Bird Treaty Act, Rivers and Harbors Act, Clean Water Act, Bald and Golden Eagle Protection Act, Fish and Wildlife Coordination Act, Marine Mammal Protection Act and National Historic Preservation Act, often requiring coordination with numerous governmental authorities. The NEPA review process can be lengthy and subjective, resulting in delays in obtaining federal approvals for projects. Our projects that are subject to the NEPA can include pipeline construction and pipeline integrity projects that involve federal lands or require approvals by federal agencies. In July 2020, the Council on Environmental Quality (“CEQ”) issued final revisions to NEPA regulations that seek to conform the scope of direct, indirect, and cumulative impact analyses for proposed projects subject to NEPA with existing case law. However, in October 2021, the CEQ published a proposed rule to restore, in general, NEPA regulations that were in effect before being modified by the 2020 revisions. The final rule has not yet been published. More stringent environmental impact analyses under or third-party challenges with respect to the sufficiency of any environmental impact statement or assessment prepared pursuant to NEPA could adversely impact such projects in the form of delays or increased compliance and mitigations costs.
Indigenous Protections. Part of our operations cross land that has historically been apportioned to various Native American/First Nations tribes (“Indigenous Peoples”), who may exercise significant jurisdiction and sovereignty over their lands. Indigenous Peoples may also have certain treaty rights and rights to consultation on projects that may affect such lands. Our
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operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Although the court’s ruling indicates that it is limited to criminal law, as applied within the Muscogee (Creek) Nation reservation, the ruling may have significant potential implications for civil law, both in the Muscogee (Creek) Nation reservation and other reservations that may similarly be found to not have been disestablished. State courts in Oklahoma have applied the analysis in McGirt in ruling that the Cherokee, Chickasaw, Seminole, and Choctaw reservations likewise had not been disestablished.
On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country within the state except: Indian allotments to which Indians titles have not been extinguished; lands that are held in trust by the United States on behalf of any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such tribe is a party and that have never been allotted to any citizen or member of such Tribe. The approval extends the State’s authority for existing EPA-approved regulatory programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling in McGirt. However, several Tribes expressed dissatisfaction with the consultation process performed in relation to this approval, and, in December 2021, the EPA proposed to withdraw and reconsider the October 2020 decision. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from EPA. At this time, we cannot predict how these jurisdictional issues may ultimately be resolved.
Human Capital Management
As of December 31, 2017, ETE2022, Energy Transfer and its consolidated subsidiaries employed an aggregate of 29,48612,565 employees, 1,5441,369 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory.good.
Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our core values in a manner that respects all people and cultures, promotes safety, and focuses on the protection of public health and the environment.
Ethics and Values. We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business. We recognize that people are our most valued resource, and we are committed to hiring and investing in employees who strive for excellence and live by our core values: working safely, corporate stewardship, ethics and integrity, entrepreneurial mindset, our people, excellence and results, and social responsibility. We value our employees for what they bring to our organization by embracing those from all backgrounds, cultures, and experiences. We also believe that the keys to our successes have been the cultivation of an atmosphere of inclusion and respect within our family of partnerships and sustaining organizations that promote diversity and provide support across all communities. These are the principles upon which we build and strengthen relationships among our people, our stakeholders, and those within the communities we support.
Respecting All People and All Cultures. We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in the best interest of the Partnership, its Unitholders, its customers, and the industry in general. In all instances, the policies of the Partnership require that the business of the Partnership be conducted in a lawful and ethical manner. Every employee acting on behalf of the Partnership must adhere to these policies. Please refer to “Item 10. Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.
Commitment to Protecting Public Health, Safety and the Environment. Protecting public health and the environment is the primary initiative for our environmental management teams, both in the construction and operation of our assets. These teams consist of environmental engineers, scientists and geologists focused on ensuring that our environmental management systems responsibly and efficiently reduce emissions, protect and preserve the land, water and air around us, and remain in compliance with all applicable regulations. Our environmental, health and safety department’s more than 200 environmental and safety professionals provide environmental and safety training to our field representatives. This group also assists others throughout the organization in identifying continuous training for personnel, including the training that is required by applicable laws, regulations, standards, and permit conditions. Our safety standards and expectations are communicated to all employees and contractors with the expectation that each individual has the obligation to make safety the highest priority. Our safety culture aims to promote an open environment for discovering, resolving, and sharing safety challenges. We strive to eliminate unwanted safety events through a comprehensive process that promotes leadership, employee involvement, communication, personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, maintaining clean facilities, contractor safety, and personal wellness. Energy Transfer’s goal is operational excellence, which means an injury- and incident-free workplace. To achieve this, we strive to hire and maintain the most qualified and dedicated workforce in the industry and make safety and safety accountability part of our daily operations. The
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OSHA Total Reportable Incident Rate (“TRIR”) is a key performance indicator by which we evaluate the success of our safety programs. TRIR provides companies with a look at their safety record performance for the year by calculating the number of recordable incidents per 200,000 hours worked. Our TRIR was 1.01 for 2022, out of more than 18 million hours worked during the year, compared to a TRIR of 0.88 for 2021. We believe the Partnership’s low TRIR speaks to the investment in and focus on safety and environmental compliance as well as the reliability of our assets.
For additional information on our Human Capital Management initiatives, please see our Corporate Responsibility Report available on our website at http://www.energytransfer.com/corporate-responsibility. Information contained on our website is not part of this report.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, theThe 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.
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ITEM 1A. RISK FACTORS
In addition to risks and uncertainties in the ordinary courseThe following is a summary of business that are common to all businesses, important risk factors that are specific to our structure as a limited partnership, ourbusiness, industry and our companypartnership structure that could materially impact our future performance and results of operations. We have provided below a list of theseThese risk factors that should be reviewed when considering an investment in our securities. ETP, PanhandleThese are not all the risks we face, and other factors that we face in the ordinary course of business, that are currently considered immaterial or that are currently unknown to us may impact our future operations.
Risk Factor Summary
Risks Related to the Partnership’s Business
Results of Operations and Financial Condition. Our results of operations and financial condition could be impacted by many risks that are beyond our control, including the following:
•fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products;
•an impairment of goodwill and intangible assets;
•an interruption of supply of crude oil to our facilities;
•the loss of any key producers or customers;
•failure to retain or replace existing customers or volumes due to declining demand or increased competition;
•unfavorable changes in natural gas price spreads between two or more physical locations;
•production declines over time, which we may not be able to replace with production from newly drilled wells;
•competition for water resources or limitations on water usage for hydraulic fracturing;
•our customers’ ability to use our pipelines and third-party pipelines over which we have no control;
•the inability to access or continue to access lands owned by third parties;
•the overall forward market for crude oil and other products we store;
•a natural disaster, catastrophe, terrorist attack or other similar event;
•extreme weather events that may be more severe or frequent than historically experienced and that may be attributable to changes in climate due to the adverse effects of an industrialized economy;
•union disputes and strikes or work stoppages by unionized employees;
•cybersecurity breaches and other disruptions or failures of our information systems;
•failure to establish or maintain adequate corporate governance;
•product liability claims and litigation, or increased insurance costs including as a result of increased risks due to the potential adverse effects of changes in climate;
•actions taken by certain of our joint ventures that we do not control;
•increasing levels of congestion in the Houston Ship Channel;
•the costs of providing pension and other postretirement health care benefits and related funding requirements;
•mergers among customers and competitors;
•fraudulent activity or misuse of proprietary data involving our outsourcing partners; and
•losses resulting from the use of derivative financial instruments.
Indebtedness. Our business, results of operations, cash flows and financial condition, as well as our ability to make distributions, could be impacted by the following:
•our debt level and debt agreements, or increases in interest rates;
•the credit and risk profile of our general partner and its owners; and
•a downgrade of our credit ratings.
Capital Projects and Future Growth. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following:
•failure to make acquisitions on economically acceptable terms, or to successfully integrate acquired assets;
•failure to secure debt and equity financing for capital projects on acceptable terms, including as a result of recent increases in cost of capital resulting from changes in monetary policy by the Federal Reserve and/or changes in financial institutions’ policies or practices concerning businesses linked to fossil fuels;
•any increased costs or reduced demand for crude oil and natural gas as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise;
•failure to construct new pipelines or to do so efficiently;
•failure to execute our growth strategy due to increased competition within any of our core businesses; and
•failure to attract and retain qualified employees; and
•failure of the liquefaction project to secure long-term contractual arrangements or necessary approvals.
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Regulatory Matters. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following:
•increased regulation of hydraulic fracturing or produced water disposal;
•legal or regulatory actions related to the Dakota Access Pipeline;
•laws, regulations and policies governing the rates, terms and conditions of our services;
•failure to recover the full amount of increases in the costs of our pipeline operations;
•imposition of regulation on assets not previously subject to regulation;
•costs and liabilities resulting from performance of pipeline integrity programs and related repairs;
•new or more stringent pipeline safety controls or enforcement of legal requirements;
•costs and liabilities associated with environmental and worker health and safety laws and regulations;
•climate change legislation or regulations restricting emissions of greenhouse gases, limiting oil and gas leases on federal lands, discouraging oil and gas development or otherwise increasing our or our customers’ costs;
•increased attention to environmental, social, and governance (“ESG”) matters and conservation measures;
•regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder;
•deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and related developments; and
•laws and regulations governing the specifications of products that we store and transport.
Risks Relating to Our Partnership Structure
Cash Distributions to Unitholders. Our cash distributions could be impacted by the following:
•our general partner’s absolute discretion in issuing an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders;
•cash distributions are not guaranteed and may fluctuate with our performance and other external factors;
•limitations on available cash that are imposed by our distribution policy;
•our general partner’s absolute discretion in determining the level of cash reserves; and
•unitholders’ potential liability to repay distributions.
Our General Partner. Our stakeholders could be impacted by risks related to our general partner, including:
•transfer of control of our general partner to a third party without unitholder consent;
•the rights of the majority owner of our general partner that protect him against dilution; and
•substantial cost reimbursements due to our general partner.
Our Subsidiaries. Risks that are unique to our subsidiaries and/or our relationship to our subsidiaries could reduce our subsidiaries’ cash available for distributions to us, including:
•the potential issuance of additional common units by Sunoco LP or USAC;
•a significant decrease in demand for or the price of motor fuel in the areas Sunoco LP serves;
•disruptions in Sunoco LP’s operations due to dangers inherent in motor fuel transportation;
•seasonal industry trends, which may cause Sunoco LP’s operating costs to fluctuate;
•adverse publicity for Sunoco LP resulting from negative events or developments;
•increased costs to retain necessary land use, which could disrupt Sunoco LP’s operations; and
•federal, state and local laws and regulations that govern the industries in which our subsidiaries operate.
Risks Related to Conflicts of Interest. Our stakeholders could be impacted by conflicts of interest, including:
•our general partner may favor its own interests to the detriment of our Unitholders;
•fiduciary duties owed to Sunoco LP, USAC and their respective unitholders by their general partners; and
•potential conflicts of interest faced by directors and officers in managing our business.
Tax Risks. Our stakeholders could be impacted by tax risks, including:
•our tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-level taxation;
•our cash available for distribution to Unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the IRS treating us as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the partnership;
•even if Unitholders do not receive any cash distributions from us, Unitholders will be required to pay taxes on their share of our taxable income;
•a Unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take; and
•treatment of distributions on Energy Transfer Preferred Units as guaranteed payments for the use of capital is uncertain and such distributions may not be eligible for the 20% deduction for qualified publicly traded partnership income.
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Risk Factor Discussion
The following discussion provides additional information regarding each of our risk factors listed above. In addition, Sunoco LP and USAC file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in ETP’s, Panhandle’s and Sunoco LP’s Annual Reports, are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.
Risks Inherent in an Investment in Us
Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.
The Parent company’s principal source of earnings and cash flow is cash distributions from ETP and Sunoco LP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP and Sunoco LP make to their partners. ETP and Sunoco LP may not be able to continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP or Sunoco LP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparableRisk Relating to the timingPartnership’s Business
Results of Operations and amount of the increase or decrease in distributions made by ETP or Sunoco LP to us.
Our ability to distribute cash received from ETP and Sunoco LP to our Unitholders is limited by a number of factors, including:
interest expense and principal payments on our indebtedness;
restrictions on distributions contained in any current or future debt agreements;
our general and administrative expenses;
expenses of our subsidiaries other than ETP and Sunoco LP, including tax liabilities of our corporate subsidiaries, if any; and
reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

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

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Furthermore, Unitholders should be aware that the amount of cash that ETP and Sunoco LPour subsidiaries have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP and Sunoco LPour subsidiaries may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related
Income from our midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the Businessesdemand for and price of natural gas, NGLs, crude oil and refined products that are beyond our control.
The prices for natural gas, NGLs, crude oil and refined products reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:
•the level of domestic natural gas, NGL, refined products and oil production;
•the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;
•actions taken by natural gas and oil producing nations;
•instability or other events affecting natural gas and oil producing nations;
•the impact of weather, geopolitical events such as the armed conflict in Ukraine and political instability in the Middle East, public health crises such as pandemics (including COVID-19), and other events of nature on the demand for natural gas, NGLs, refined products and oil;
•the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
•the price, availability and marketing of competitive fuels;
•supply chain disruptions and inflation;
•the demand for electricity;
•activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas and related products;
•rising interest rates and slowing economic growth;
•the cost of capital needed to maintain or increase production levels and to construct and expand facilities;
•the impact of energy conservation and fuel efficiency efforts; and
•the extent of governmental regulations, taxation, fees and duties.
In the past, the prices of natural gas, NGLs, refined products and oil have been extremely volatile, and we expect this volatility to continue.
Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs, refined products or oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL, refined products and oil commodities could materially affect our profitability.
Our business could be negatively impacted by inflationary pressures which may decrease our operating margins and increase working capital investments required to operate our business.
The U.S. economy has experienced rising inflation in 2022. A sustained increase in inflation may continue to increase our costs for labor, services, and materials. Further, our producer suppliers and customers face inflationary pressures and resulting impacts, such as the tight labor market, availability of drilling and hydraulic fracturing equipment, and supply chain disruptions, which could increase the cost of production which in turn may limit the level of drilling activity in the regions in which we operate. Our throughput volumes may be impacted if producers are constrained. The rate and scope of these various inflationary factors may increase our operating costs and capital expenditures materially, which may not be readily recoverable in the prices of our Subsidiaries” includedservices and may have an adverse effect on our results of operations and financial condition.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2022, our consolidated balance sheet reflected $2.6 billion of goodwill and $5.4 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 this Item 1Athe 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,
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we would be required to take an immediate charge to earnings with a discussioncorrelative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.
We depend on certain key producers for our supply of further risks affecting ETP’snatural gas and Sunoco LP’s abilitythe loss of any of these key producers could adversely affect our financial results.
Certain producers who are connected to generate distributableour systems represent a material source of our supply of natural gas. We are not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.
Our intrastate transportation and storage and interstate transportation and storage operations depend on key customers to transport natural gas through our pipelines and the pipelines of our joint ventures.
During 2022, two customers accounted for approximately 42% of our intrastate transportation and storage revenues. During 2022, four customers collectively accounted for 39% of our interstate transportation and storage revenues.
Certain of our joint ventures also depend on key customers. Citrus has long-term agreements with its top two customers which accounted for 52% of its 2022 revenue. For the Trans-Pecos and Comanche Trail pipelines, a single customer is the primary shipper.
The failure of the major shippers on our and our joint ventures’ intrastate and interstate transportation and storage pipelines to fulfill their contractual obligations could have a material adverse effect on our cash flow.flow and results of operations if we or our joint ventures were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
We may issue an unlimitedbe unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in crude oil, refined products, natural gas and NGL markets, which would reduce our revenues and limit our future profitability.
The retention or replacement of existing customers and the volume of services that we provide at rates sufficient to maintain or increase current revenues and cash flows depends on a number of limited partner interestsfactors beyond our control, including the price of and demand for crude oil, refined products, natural gas and NGLs in the markets we serve and competition from other service providers.
A significant portion of our 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.
We also receive a substantial portion of our revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of our services are sold under long-term contracts for reserved service, we 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 our 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. We receive substantially all of our transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to our transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other classesfactors, however, may result lower rates of equity without the consentproduction under dedicated contracts and lower demand for our services. In addition, our refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of our Unitholders,revenue is derived from fungible storage and throughput arrangements, under which our revenue is more dependent upon demand for storage from our customers.
The volume of crude oil and refined products transported through our crude oil and refined products pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A
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period of sustained price reductions for crude oil or refined products could lead to a decline in drilling activity, production and refining of crude oil or import levels in these areas. A period of sustained increases in the price of crude oil or refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or refined products in these areas. In either case, the volumes of crude oil or refined products transported in our crude oil and refined products pipelines and terminal facilities could decline.
The loss of existing customers by our midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services our customers purchase from us, or our inability to attract new customers and service volumes would negatively affect our revenues, be detrimental to our growth, and adversely affect our results of operations.
We and our subsidiaries, including Sunoco LP and USAC, are exposed to the credit risk of our customers and derivative counterparties, and an increase in the nonpayment and nonperformance by our customers or derivative counterparties could reduce our ability to make distributions to our Unitholders.
We, Sunoco LP and USAC are subject to risks of loss resulting from nonpayment or nonperformance by our, Sunoco LP’s and USAC’s customers. Commodity price volatility and/or 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 our customers. 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 our customers could have a material effect on our, Sunoco LP’s and USAC’s results of operations and operating cash flows.
Severe market disruptions could cause some of our counterparties to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court. Following the request of one of our FERC-regulated natural gas pipelines, the FERC commenced a proceeding to determine whether the public interest requires abrogation or modification of a firm transportation agreement with one of our shippers. By order dated November 9, 2020, FERC held that the record did not support a finding that the public interest presently required abrogation or modification of the subject firm transportation agreement. The shipper subsequently filed for bankruptcy. Thereafter, on July 19, 2022, the Fifth Circuit Court of Appeals rejected FERC’s jurisdictional basis for its earlier public interest decision, vacated the November 9, 2020 order and a settlement has been reached regarding the agreement in the underlying bankruptcy proceeding. We will dilute Unitholders’attempt to remarket the subject capacity and, depending on the availability of alternatives to our services, any resulting contracts may have terms that are less favorable to us than the former shipper’s contract.
The profitability of certain activities in our natural gas gathering, processing, transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.
For a portion of the natural gas gathered on our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.
We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers.
Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements, our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our revenues and results of operations.
Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.
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When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.
We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.
In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.
For our midstream segment, we generally analyze gross margin based on fee-based margin (which includes revenues from processing fee arrangements) and non-fee-based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). The amount of segment margin earned by our midstream segment from fee-based and non-fee-based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non-fee-based arrangements in future periods may be significantly different from results reported in previous periods.
Our midstream facilities and transportation pipelines provide services related to natural gas wells that experience production declines over time, which we may not be able to replace with natural gas production from newly drilled wells in the same natural gas basins or in other new natural gas producing areas.
In order to maintain or increase throughput levels on our gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies and natural gas transportation services.
A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. Our 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. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our 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 our transportation pipelines or markets to which our systems connect. We have no control over the level of drilling activity in our areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, we have no control over producers or their production and contracting decisions.
While a substantial portion of our services are provided under long-term contracts for reserved service, we also provide 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 we provide and a decrease in the number and volume of our contracts for reserved transportation service over the long run, which in each case would adversely affect our 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.
Our revenues depend on our customers’ ability to use our pipelines and third-party pipelines over which we have no control.
Our natural gas transportation, storage and NGL businesses depend, in part, on our customers’ ability to obtain access to pipelines to deliver gas to us and receive gas from us. 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 our ability, and the ability of our customers, to transport natural gas to and from our pipelines and facilities and a corresponding material adverse effect on our transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by those pipelines
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or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.
Shippers using our oil pipelines and terminals are also dependent upon our 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 our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in its pipelines or through our 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 our results of operations, financial position, or cash flows.
The inability to continue to access lands owned by third parties could adversely affect our ability to operate and our financial results.
Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including, private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. For more information, see our regulatory disclosure titled “Indigenous Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.
Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent down rights or negotiate private agreements cases, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. For example, following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where 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 our real property, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to Unitholders.
Our storage operations are influenced by the overall forward market for crude oil and other products we store, and certain market conditions may adversely affect our financial and operating results.
Our storage operations are influenced by the overall forward market for crude oil and other products we store. A contango market (meaning that the price of crude oil or other products for future delivery is higher than the current price) is associated with greater demand for storage capacity, because a party can simultaneously purchase crude oil or other products at current prices for storage and sell at higher prices for future delivery. A backwardated market (meaning that the price of crude oil or other products for future delivery is lower than the current price) is associated with lower demand for storage capacity because a party can capture a premium for prompt delivery of crude oil or other products rather than storing it for future sale. A prolonged backwardated market, or other adverse market conditions, could have an adverse impact on its ability to negotiate favorable prices under new or renewing storage contracts, which could have an adverse impact on our storage revenues. As a result, the overall forward market for crude oil or other products may have an adverse effect on our financial condition or results of operations.
Competition for water resources or limitations on water usage for hydraulic fracturing could disrupt crude oil and natural gas production from shale formations.
Hydraulic fracturing is the process of creating or expanding cracks by pumping water, sand and chemicals under high pressure into an underground formation in order to increase the productivity of crude oil and natural gas wells. Water used in the process is generally fresh water, recycled produced water or salt water. There is competition for fresh water from municipalities, farmers, ranchers and industrial users. In addition, the available supply of fresh water can also be reduced directly by drought. Prolonged drought conditions increase the intensity of competition for fresh water. Limitations on oil and gas producers’ access to fresh water may restrict their ability to use hydraulic fracturing and could reduce new production. Such disruptions could potentially have a material adverse impact on our financial condition or results of operations.
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A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow.
Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas pipeline and other facilities operate at high pressures. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
If one or more facilities that are owned by us, or that deliver natural gas or other products to us, are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our 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 our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to Unitholders.
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, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may increasebe insufficient if such an event were to occur.
Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.
The United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the riskfuture 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 our facilities or pipelines, those of our customers, or in some cases, those of other pipelines could have a material adverse effect on our business, financial condition and results of operations.
Our business could be affected adversely by union disputes and strikes or work stoppages by unionized employees.
As of December 31, 2022, approximately 11% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have sufficient availablea material adverse effect on our business, financial position, results of operations or cash to maintainflows.
Cybersecurity attacks, data breaches and other disruptions affecting us, or increase our per unit distribution level.service providers, could materially and adversely affect our business, operations, reputation, and financial results.
Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approvalThe security and integrity of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:
our Unitholders’ current proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each Common Unit or partnership security may decrease;
the ratio of taxable incomeinformation technology infrastructure and physical assets are critical to distributions may increase;
the relative voting strength of each previously outstanding Common Unit may be diminished; and
the market price of our Common Units may decline.
In addition, ETP and Sunoco LP may sell an unlimited number of limited partner interests without the consent of the respective Unitholders, which will dilute existing interests of the respective Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP or Sunoco LP will have essentially the same effects as detailed above.
ETP and Sunoco LP may issue additional Common Units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.
The partnership agreements of ETP and Sunoco LP allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:
Unitholders’ current proportionate ownership interest in each partnership will decrease;
the amount of cash available for distribution on each common unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of each partnership’s common units may decline.
The payment of distributions on any additional units issued by ETP and Sunoco LP may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.
Unitholders have limited voting rights and are not entitled to elect the General Partner or its directors. In addition, even if Unitholders are dissatisfied, they cannot easily remove the General Partner.
Unlike the holders of common stock in a corporation, Unitholders have only limited voting rights on matters affecting our business and therefore limitedour ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partnerperform day-to-day operations and will have no right to elect our General Partner ordeliver services. In addition, in the officers or directorsordinary course of our General Partnerbusiness, we collect, process, transmit and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, as well as personally identifiable information, in our data centers and on an annual our networks. We also engage third parties, such as service providers and vendors, who provide a broad array of software, technologies, tools, and other products, services and functions (e.g., human resources, finance, data transmission, communications, risk, compliance, among others) that enable us to conduct, monitor and/or protect our business, operations, systems and data assets.
Our information technology and infrastructure, physical assets and data, may be vulnerable to unauthorized access, computer viruses, malicious attacks and other continuing basis.
Furthermore,events (e.g., distributed denial of service attacks, ransomware attacks) that are beyond our control. These events can result from malfeasance by external parties, such as hackers, or due to human error by our or our service providers’ employees and contractors (e.g., due to social engineering or phishing attacks). In addition, a new development similar to the COVID-19 pandemic could present additional operational and cybersecurity risks to our information technology infrastructure and physical assets if our Unitholders are dissatisfied with the performanceproviders begin or resume work-from-home arrangements.
We and certain of our General Partner, theyservice providers have, from time to time, been subject to cyberattacks and security incidents. The frequency and magnitude of cyberattacks is expected to increase and attackers are becoming more sophisticated. We may be
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unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove our General Partner. Our General Partner may not be removed except, among other things, upon the vote of the holders of at least 66 2/3%or obfuscate forensic evidence.
Breaches of our outstanding units. Asinformation technology infrastructure or physical assets, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of December 31, 2017,contracts, and have a material adverse effect on our directorsoperations, financial position and executive officers directlyresults of operations. A successful cyberattack or indirectly own approximately 27%other security incident could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or loss could result in legal claims or proceedings, regulatory investigations and enforcement, penalties and fines, increased costs for system remediation and compliance requirements, disruption of our outstanding Common Units. It will be particularly difficult for our General Partner to be removed without the consent of our directors and executive officers. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

Furthermore, Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the General Partner and its affiliates, cannot be voted on any matter.
Our General Partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.
Pursuantoperations, damage to our partnership agreement, our General Partner has the ability, in its sole discretion and without the approvalreputation, or loss of the Unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our General Partner, including:
the right to share in the Partnership’s profits and losses;
the right to share in the Partnership’s distributions;
the rights upon dissolution and liquidation of the Partnership;
whether, and the terms upon which, the Partnership may redeem the securities;
whether the securities will be issued, evidenced by certificates and assigned or transferred; and
the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.
Please see “—We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.” above.
The control of our General Partner may be transferred to a third party without Unitholder consent.
The General Partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the members of our General Partner may transfer all or part of their ownership interestconfidence in our General Partner to a third party without the consentproducts and services, any or all of the Unitholders. Any new owner or owners of our General Partner or the general partner of the General Partner would be in a position to replace the directors and officers of our General Partner with its own choices and to control the decisions made and actions taken by the board of directors and officers.
We are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.
We rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business. Mr. Warren has been integral to the success of ETP’s midstream and intrastate transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing the leadership of Mr. Warren could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s abilityour business and results. We may be required to increaseinvest significant additional resources to comply with evolving cybersecurity regulations and to modify and enhance our information security and controls, and to investigate and remediate any security vulnerabilities. Any losses, costs or liabilities may not be covered by, or may exceed the cash distributions paidcoverage limits of, any or all of our applicable insurance policies.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on its partnershipfinancial, 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.
Product liability claims and litigation could adversely affect our business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.
Along with other refiners, manufacturers and sellers of gasoline, ETC Sunoco is a defendant in numerous lawsuits that allege 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 ETC Sunoco. An adverse determination of liability related to these allegations or other product liability claims against ETC Sunoco could have a material adverse effect on our business or results of operations.
We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.
Certain of our operations are conducted through joint ventures, some of which have their own governing boards. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in their or the joint venture’s best interests. Likewise, we may be unable to prevent actions of the joint venture. Differences in views among joint venture partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.
ETP’s executive officers that provide servicesThe use of derivative financial instruments could result in material financial losses by us.
From time to us pursuanttime, we and/or our subsidiaries have sought to a shared services agreement allocate their time between usreduce our exposure to fluctuations in commodity prices and ETP.interest rates by using derivative financial instruments and other risk management mechanisms and by our trading, marketing
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and/or system optimization activities. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.
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 officers face conflicts regardingtransactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the allocationderivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.
Increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports.
Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston, which is currently the busiest port in the U.S. by waterborne tonnage and which has increased volumes in each of the last two years, could cause our customers or potential customers to divert their business to smaller ports in the Gulf of Mexico, which could result in lower utilization of our facilities.
The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.
Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their time, weemployees. 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 receiverecover all of the levelcosts 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 attention from them thatthese benefits on operating results could significantly increase.
Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the managementcombined 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.
Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.
We utilize both affiliated entities and third parties in the processing of our information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information, or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss, or misuse of this information, result in litigation and potential liability, lead to reputational damage, increase our compliance costs, or otherwise harm our business.
Our trucking fleet operations are subject to the Federal Motor Carrier Safety Regulations which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). Our fleet currently has a “satisfactory” safety
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rating; however, if our safety rating were downgraded to “unsatisfactory,” our business requires. If ETP is unable to provide us with a sufficient numberand results of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controlsoperations could be adversely impacted.affected.
Cost reimbursements dueAll federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections as opposed to our General Partner may be substantialcompliance audits performed by the FMCSA. The quantity and may reduce our abilityseverity of any violations are compared to paya peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the distributionsFMCSA, it is subject to our Unitholders.
Prioraction from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurredon-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of its operating authority by the FMCSA could have an adverse effect on our behalf. In addition, our General Partnerbusiness, results of operations and its affiliatesfinancial condition.
Indebtedness
Our debt level and debt agreements 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 affectlimit our ability to make distributions to Unitholders and may limit our Unitholders.future financial and operating flexibility.
As of December 31, 2022, we had approximately $48.26 billion of consolidated debt, excluding the debt of our unconsolidated joint ventures. Our General Partner has sole discretionlevel of indebtedness affects our operations in several ways, including, among other things:
•a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to determine the amountpayment of these expensesprincipal and fees.
In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debtsinterest on outstanding debt 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 cashwill not be available for distributionother purposes, including payment of distributions;
•covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our Unitholdersflexibility in planning for and cause the valuereacting to changes in our business;
•our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
•we may be at a competitive disadvantage relative to similar companies that have less debt;
•we may be more vulnerable to adverse economic and industry conditions as a result of our Common Unitssignificant debt level; and
•failure by us or our subsidiaries to decline.
A reduction in ETP’s or Sunoco LP’s distributions will disproportionately affectcomply with the amountvarious restrictive covenants of cash distributionsour respective debt agreements could negatively impact our ability to which ETE is entitled.
ETE indirectly owns all ofincur additional debt, including our ability to utilize the IDRs of ETPavailable capacity under our revolving credit facility, and Sunoco LP. These IDRs entitle the holderour ability to receive increasing percentages of total cash distributions made by each of ETP and Sunoco LP as such entity reaches established target cash distribution levels as specified in its partnership agreement. ETE currently receives its pro rata share of cash distributions from ETP and Sunoco LP based on the highest sharing level of 48% and 50% in respect of the ETP IDRs and Sunoco LP IDRs, respectively.
A decrease in the amount of distributions by ETP to ETE to less than $0.2638 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from ETP above $0.0958 per unit per quarter from 48% to 35%, and a decrease in the amount of distributions by Sunoco LP to ETE to less than $0.6563 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from Sunoco LP above $0.5469 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from the ETP or Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that ETE and ETP receive, based on their ownership interest in the IDRs as compared to cash distributions they receive from their general partner interest and common units in such entity.pay our distributions.
The consolidated debt level and debt agreements of ETP andour subsidiaries, including Sunoco LP and those of their subsidiariesUSAC, may limit the distributions we receive from ETP and Sunoco LP,these subsidiaries, as well as our future financial and operating flexibility.
ETP’s and Sunoco LP’sOur subsidiaries’ levels of indebtedness affect their operations in several ways, including, among other things:
•a significant portion of ETP’s and Sunoco LP’s and theirour subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;
•covenants contained in ETP’s and Sunoco LP’s and theirour subsidiaries’ existing debt agreements require ETP, Sunoco LP and theirthe respective subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
ETP’s and Sunoco LP’s and their•our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
ETP and Sunoco LP•our subsidiaries may be at a competitive disadvantage relative to similar companies that have less debt;
ETP and Sunoco LP•our subsidiaries may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;
•failure by ETP, Sunoco LP or theirour subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETP’s and Sunoco LP’sthe respective subsidiaries’ ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.
We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.
Unlike a corporation, our partnership agreementPartnership Agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our partnership agreement)Partnership Agreement) to our Unitholders of record and our General Partner.general partner. Available Cash is generally all of
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our cash on hand as of the end of a quarter, adjusted for cash distributions and net changes to reserves. Our General Partnergeneral partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:
•to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);
•to provide funds for distributions to our Unitholders and our General Partnergeneral partner for any one or more of the next four calendar quarters; or
•to comply with applicable law or any of our loan or other agreements.

A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratings might increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
economic downturns;
deteriorating capital market conditions;
declining market prices for crude oil, natural gas, NGLs and other commodities;
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Our subsidiaries are not prohibited from competing with us.
Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETP and Sunoco LP, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Capital projects will require significant amounts of debt and equity financing, which may not be available to ETP on acceptable terms, or at all.
ETP plans to fund its growth capital expenditures, including any new future pipeline construction projects and improvements or repairs to existing facilities that ETP may undertake, with proceeds from sales of ETP’s debt and equity securities and borrowings under its revolving credit facility; however, ETP cannot be certain that it will be able to issue debt and equity securities on terms satisfactory to it, or at all. In addition, ETP may be unable to obtain adequate funding under its current revolving credit facility because ETP’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP is unable to finance its expansion projects as expected, ETP could be required to seek alternative financing, the terms of which may not be attractive to ETP, or to revise or cancel its expansion plans.
A significant increase in ETP’s indebtedness that is proportionately greater than ETP’s issuance of equity could negatively impact ETP’s credit ratings or its ability to remain in compliance with the financial covenants under its revolving credit agreement, which could have a material adverse effect on ETP’s financial condition, results of operations and cash flows.
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates.rates, including the significant increases in prevailing interest rates as a result of changes in federal monetary and fiscal policy. Approximately $9.86$3.16 billion of our consolidated debt as of December 31, 20172022 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 could impact demand for our storage capacity.
There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user, in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing crude oil for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
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.
A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
•economic downturns;
•deteriorating capital market conditions;
•declining market prices for crude oil, natural gas, NGLs and other commodities;
•terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
•the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.
Capital Projects and Future Growth
If we and our subsidiaries do not make acquisitions on economically acceptable terms, our future growth could be limited.
Our results of operations and our ability to grow and to make distributions to Unitholders will depend in part on our ability to make acquisitions that are accretive to our distributable cash flow per unit.
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We may be unable to make accretive acquisitions for any of the following reasons, among others:
•because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
•because we are unable to raise financing for such acquisitions on economically acceptable terms; or
•because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.
Furthermore, even if we consummate acquisitions that we believe will be accretive, those acquisitions may in fact adversely affect our results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that we may:
•fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
•decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
•significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•encounter difficulties operating in new geographic areas or new lines of business;
•incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;
•be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;
•less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or
•incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that we will consider.
Capital projects will require significant amounts of debt and equity financing, which may not be available to us on acceptable terms, or at all.
We plan to fund our growth capital expenditures, including any new pipeline construction projects and improvements or repairs to existing facilities that we may undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms satisfactory to us, or at all. If we are unable to finance our expansion projects as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our expansion plans.
A significant increase in our indebtedness that is proportionately greater than our issuance of equity could negatively impact our and our subsidiaries’ credit ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement, which could have a material adverse effect on our financial condition, results of operations and cash flows.
The Inflation Reduction Act of 2022 could decrease demand for crude oil and natural gas and could impose new costs on our operations.
In August 2022, President Biden signed the IRA 2022, which contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA 2022 imposes the first-ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their greenhouse gas emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. In addition, the multiple incentives offered for various clean energy industries referenced above could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.
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If we do not continue to construct new pipelines, our future growth could be limited.
Our results of operations and ability to grow and to increase distributable cash flow per unit will depend, in part, on our ability to construct pipelines that are accretive to our distributable cash flow. We may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:
•we are unable to identify pipeline construction opportunities with favorable projected financial returns;
•we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms;
•we are unable to raise financing for our identified pipeline construction opportunities; or
•we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
Furthermore, even if we construct a pipeline that we believe will be accretive, the pipeline may in fact adversely affect our results of operations or results from those projected prior to commencement of construction and other factors.
Expanding our business by constructing new pipelines and related facilities subjects us to risks.
One of the ways that we have grown our business is through the construction of additions to our existing gathering, compression, treating, processing and transportation systems. The construction of new pipelines and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be completed on schedule, at all, or at the budgeted cost. A variety of factors outside our 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. For example, in recent years, pipeline projects by many companies have been subject to several challenges by environmental groups, such as challenges to agency reviews under the NEPA and to the USACE NWP program. Any changes to the USACE NWP program that exclude our projects from coverage could require us to reroute pipeline projects, or seek individual permits that involve longer permitting timelines, leading to construction delays. For more information on the NWP program, see our regulatory disclosure titled “Clean Water Act.” Separately, cost overruns or delays in completing a project could have a material adverse effect on our results of operations and cash flows. Moreover, our revenues may not increase immediately following the completion of a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, but we may not materially increase our 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 our ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, we 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 our expected investment return, which could adversely affect our results of operations and financial condition.
The liquefaction project is dependent upon securing long-term contractual arrangements for the off-take of LNG on terms sufficient to support the financial viability of the project.
Lake Charles LNG Export, our wholly-owned subsidiary, is in the process of developing a liquefaction project at the site of our existing regasification facility in Lake Charles, Louisiana. The project would utilize existing dock and storage facilities owned by us located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia). Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.
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The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.
While Lake Charles LNG Export has received authorization from the DOE to export LNG to non-Free Trade Agreements (“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 FERC order (issued December 17, 2015) authorizing Lake Charles LNG Export to site, construct and operate the liquefaction project contains a condition requiring all phases of the liquefaction project to be completed and in-service within five years of the date of the order. The order also requires the modifications to our Trunkline pipeline facilities that connect to our Lake Charles facility and additionally requires execution of a transportation contract for natural gas supply to the liquefaction facility prior to the initiation of construction of the liquefaction facility. On December 5, 2019, the FERC granted an extension of time until and including December 16, 2025, to complete construction of the liquefaction project and pipeline facilities modifications and place the facilities into service. On January 31, 2022, Lake Charles LNG Export filed seeking an extension of time until and including December 16, 2028 to complete construction of the liquefaction facilities modifications and place the facilities into service. The FERC issued an order granting the extension of time request on May 6, 2022.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to Unitholders.
The difficulties of integrating past and future acquisitions with our business include, among other things:
•operating a larger combined organization in new geographic areas and new lines of business;
•hiring, training or retaining qualified personnel to manage and operate our growing business and assets;
•integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;
•diversion of management’s attention from our existing business;
•assimilation of acquired assets and operations, including additional regulatory programs;
•loss of customers or key employees;
•maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and
•integrating new technology systems for financial reporting.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.
We are affected by competition from other midstream, transportation, terminalling and storage companies.
We experience competition in all of our business segments. With respect to our midstream operations, we compete for both natural gas supplies and customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.
Our natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors,
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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.
Our crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude and refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
We, Sunoco LP and USAC may not be able to fully execute our growth strategy if we encounter increased competition for qualified assets.
Our strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that we believe will present opportunities to realize synergies and increase our cash flow.
Consistent with our strategy, we 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 our participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot give assurance that our acquisition efforts will be successful or that any acquisition will be completed on terms considered favorable to us.
In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in us losing to other bidders more often or acquiring assets at higher prices, both of which would limit our ability to fully execute our growth strategy. Inability to execute our growth strategy may materially adversely impact our results of operations.
We compete with other businesses in our market with respect to attracting and retaining qualified employees.
Our continued success depends on our ability to attract and retain qualified personnel in all areas of our business. We compete with other businesses in our market with respect to attracting and retaining qualified employees. A tight labor market, increased overtime and a higher full-time employee ratio may cause labor costs to increase. A shortage of qualified employees may require us to enhance wage and benefits packages in order to compete effectively in the hiring and retention of such employees or to hire more expensive temporary employees. No assurance can be given that our labor costs will not increase, or that such increases can be recovered through increased prices charged to customers. We are especially vulnerable to labor shortages in oil and gas drilling areas when energy prices drive higher exploration and production activity.
Regulatory Matters
Litigation commenced by The Williams Companies, Inc (“Williams”) against Energy Transfer and its affiliates could require Energy Transfer to make a substantial payment to Williams.
Williams filed a complaint against Energy Transfer and its affiliates (“Energy Transfer Defendants”) in the Delaware Court of Chancery (the “Court”), alleging that the Energy Transfer Defendants breached the merger agreement (the “Merger Agreement”) between Williams, Energy Transfer, and several of Energy Transfer’s affiliates by (i) failing to use commercially reasonable efforts to obtain the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code, (ii) issuing the Partnership’s series A convertible preferred units (the “Issuance���), and (c) making allegedly untrue representations and warranties in the Merger Agreement (collectively, the “Williams Litigation”). Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the Merger Agreement by Energy Transfer on June 29, 2016, Williams filed a notice of appeal to the Supreme Court of Delaware. Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee (the “Termination Fee”) and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that the Energy Transfer Defendants breached an additional representation and warranty in the Merger Agreement. The Energy Transfer Defendants filed amended counterclaims and affirmative defenses on
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September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss the Energy Transfer Defendant’ amended counterclaims and to strike certain of the Energy Transfer Defendants’ affirmative defenses. On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying it in part. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s June 24, 2016 ruling, and as a result, Williams conceded that its $10 billion damages claim is foreclosed, although the Termination Fee claim remained pending.
Trial was held regarding the parties’ amended claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court did not reach Williams’ tax-related claims.
On September 21, 2022, the Court entered a final judgment against the Energy Transfer Defendants in the amount of approximately $601 million plus post-judgment interest at a rate of 3.5% per year. The Energy Transfer Defendants filed the notice of appeal of this matter on October 21, 2022 and filed their opening brief in support of their appeal on December 30, 2022. Williams filed their answering brief on January 20, 2023, and the Energy Transfer Defendants filed their reply brief on February 6, 2023.
Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our areas of operation, which could adversely impact our business and results of operations.
The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health, safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. Additionally, several candidates for political office in both state and federal government have announced intentions to impose greater restrictions on hydraulic fracturing or produced water disposal. For example, on January 27, 2021, the Biden Administration issued an executive order temporarily suspending the issuance of new authorizations, and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters (but not tribal lands that the federal government merely holds in trust). The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, followed by a permanent injunction in August 2022, effectively halting implementation of the leasing suspension. Relatedly, the Department of the Interior (“DOI”) released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. In 2022, the recommendations in this report resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate. Implementation of many of the recommendations in the DOI report will require Congressional action and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and adversely impact our business. Separately, in November 2022, the BLM proposed a rule that would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if the BLM finds that an operator’s methane waste minimization plan is insufficient. In addition, the Colorado Oil and Gas Conservation Commission adopted new rules to cover a variety of matters related to public health, safety, welfare, wildlife, and environmental resources; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, additional restrictions for oil and gas activities, such as requiring even greater setbacks. While the final impacts of these developments cannot be predicted, the adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or produced water disposal or prohibiting hydraulic fracturing in proximity to areas considered to be environmentally sensitive could make drilling certain wells impossible or less economically attractive. As a result, the volume of crude oil and natural gas we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our financial condition or results of operations.
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Legal or regulatory actions related to the Dakota Access Pipeline could cause an interruption to current or future operations, which could have an adverse effect on our business and results of operations.
On July 27, 2016, the Standing Rock Sioux Tribe and other Native American tribes (the “Tribes”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the USACE permitting Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. As a result of this litigation, the District Court vacated the easement, ordered USACE to prepare an Environmental Impact Statement (“EIS”), and order the pipeline shutdown and drained of oil. Dakota Access and USACE appealed this decision and moved for a stay of the District Court’s orders. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, but the Court of Appeals denied a stay of the easement vacatur. The August 5, 2020 order also stated that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intends to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary. Following this order, the Tribes filed a motion with the District Court seeking an injunction to prevent the continued operation of the pipeline. On January 26, 2021, the Court of Appeals affirmed the District Court’s order requiring an EIS and its order vacating the easement. In the same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline be shut down and emptied of oil because of the lack of findings sufficient to satisfy the legal requirements for injunctive relief, including a finding of irreparable harm to the Tribes in the absence of an injunction. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and plaintiffs, and Dakota Access has filed its reply.
The District Court scheduled a status conference for February 10, 2021 to discuss the impact of the Court of Appeals’ ruling on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed in light of the Court of Appeals’ recent vacatur ruling. USACE filed a motion for a continuance of the status conference until April 9, 2021, and this motion was approved by the District Court on February 9, 2021. Dakota Access and the Tribes filed their supplemental declarations on April 19, 2021 and April 26, 2021, respectively. On April 26, 2021, the District Court requested that USACE advise it by May 3, 2021 as to USACE’s current position, if it has one, with respect to the motion. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. The USACE also advised the District Court that it expected that the EIS will be completed by March 2022. On May 21, 2021 the District Court denied the plaintiffs’ request for an injunction. The District Court further directed the parties to file a joint status report by June 11, 2021 concerning potential next steps in the litigation. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing Rock Sioux Tribe withdrew as a cooperating agency on the draft EIS, prompting the USACE to temporarily pause on the draft EIS. Although we are not certain as to the timeline, the USACE now estimates that the draft EIS will be published sometime in the spring of 2023. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.
Our interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.
Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our 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.
We are required to file with the FERC tariff rates (also known as recourse rates) that shippers may 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. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.
The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against us and find that our rates were not just and reasonable or were unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could have an adverse effect on our revenues and results of operations.
The costs of our interstate pipeline operations may increase, and we may not be able to recover all of those costs due to FERC regulation of our rates. If we propose to change our tariff rates, our proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit our proposed changes if we are unable to persuade the FERC that changes
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would result in just and reasonable rates that are not unduly discriminatory. We 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 we may be constrained by competitive factors from charging our tariff rates.
To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our 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. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.
The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity (“ROE”) calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts that FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC regulated transportation services are unknown at this time.
Even without application of FERC’s recent rate making-related policy statements and rulemakings, under the NGA, FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of a pipeline’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding. On December 16, 2022, the FERC issued its order on Panhandle’s rate case. On January 17, 2023, Panhandle filed its request for rehearing in the proceeding.
On July 1, 2022, Transwestern filed a rate case pursuant to Section 4 of the Natural Gas Act. By order dated September 9, 2022, a procedural schedule was adopted in this proceeding, setting the commencement of the hearing for June 22, 2023 with an initial decision anticipated by November 15, 2023. By a subsequent order dated February 14, 2023, the procedural schedule was suspended based on representations that the participants have reached an agreement in principle to resolve all issues in this proceeding and a settlement is being prepared for filing at FERC.
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On December 1, 2022, Sea Robin filed a general rate proceeding under Section 4 of the NGA reflecting a general rate increase for gathering and transportation services. A hearing in the proceeding is scheduled for October 24, 2023 with an initial decision anticipated by March 19, 2024.
Our interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect our business and results of operations.
In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of our interstate natural gas pipelines, including:
•terms and conditions of service;
•the types of services interstate pipelines may or must offer their customers;
•siting and construction of new facilities;
•acquisition, extension or abandonment of services or facilities;
•reporting and information posting requirements;
•accounts and records; and
•relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
Compliance with these requirements can be costly and burdensome. In addition, we cannot guarantee that the FERC will authorize tariff changes and other activities we might propose and to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair our access to capital markets or may impair the ability of our interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.
The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018 (“2018 NOI”) initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities (“1999 Policy Statement”), issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the Natural Gas Act. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022. On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certificate of New Interstate Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft 2022 Policy Statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments were due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and refined products pipeline operations.
Transportation provided on our common carrier interstate crude oil, NGL and refined products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If we propose 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
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rates that reflect increased costs. On March 25, 2020, the FERC issued a Notice of Inquiry seeking comment on a proposal to change the preliminary screen for complaints against oil pipeline index rate increases to a “Percentage Comparison Test” consistent with the preliminary screen used by the FERC for protests against oil pipeline index rate increases. The FERC also requested comment on whether the appropriate threshold for the screen is a 10% or more differential between a proposed index rate increase and the annual percentage change in cost of service reported by the pipeline. Initial comments were due June 16, 2020, and reply comments were due July 16, 2020.
On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases. Specifically, the policy statement adopted the proposal in the FERC’s earlier Notice of Inquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen applied to complaints against index rate increases and instead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.
On June 18, 2020, FERC issued a NOI requesting comments on a proposed oil pipeline index for the five-year period commencing July 1, 2021 and ending June 30, 2026, and requested comments on whether and how the index should reflect the Revised Policy Statement and FERC’s treatment of accumulated deferred income taxes as well as FERC’s revised ROE methodology.
On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit.
Under the Energy Policy Act of 1992 (the “Energy Policy Act”), certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.
If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.
State regulatory measures could adversely affect the business and operations of our midstream and intrastate pipeline and storage assets.
Our midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects our business and the market for our products. The rates, terms and conditions of service for the interstate services we provide in our intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our pipeline systems of Enable Oklahoma Intrastate Transmission, LLC, Oasis Pipeline, LP, Houston Pipe Line Company LP, ETC Katy Pipeline, LLC, Energy Transfer Fuel, LP, Lobo Pipeline Company, LLC, Pelico Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail Pipeline, LLC 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 our costs of service, our cash flow would be negatively affected.
Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation. All of the states in which we operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which we operate have
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ratable take statutes, which generally require gathering pipelines 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, our business may be adversely affected.
Our 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.
We are subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.
Certain of our assets may become subject to regulation.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.
Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Energy Transfer GC NGL’s pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Energy Transfer GC NGL’s pipeline also commenced the interstate transportation of NGLs, which is subject to the FERC’s jurisdiction under the Interstate Commerce Act (“ICA”) and the Energy Policy Act. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if the FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by the FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, NGPA, or ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to authority under the NGPSA and HLPSA, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”) which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the
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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 October 2019, PHMSA published the first of three regulations relating to new or more stringent requirements for certain natural gas lines and gathering lines, that had originally been proposed in 2016 as part of PHMSA’s “Gas Megarule.” The rulemaking imposed numerous requirements on onshore gas transmission pipelines relating to MAOP, reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs, non-HCAs, Class 3 and Class 4 areas by 2023, and the consideration of seismicity as a risk factor in integrity management. PHMSA’s second final rule, applicable to hazardous liquid transmission and gathering pipelines, significantly extended and expanded the reach of certain integrity management requirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to permit such use), increased annual, accident, and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. The third final rule was published in August 2022, which adjusted the repair criteria for pipelines in HCAs, created new criteria for pipelines in non-HCAs, and strengthened integrity management assessment requirements, among other items. The changes adopted by these rulemakings could have a material adverse effect on our results of operations and costs of transportation services.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. In March 2022, PHMSA issued a final rule increasing the maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $239,142 per day, with a maximum of $2,391,412 for a series of violations. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings. For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking, To that end, PHMSA issued the three final rules discussed above, significantly expanding reporting and safety requirements of operators of gas gathering pipelines, imposing safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators, and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Additionally, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas from related pipeline facilities. The safety enhancement requirements and other provisions of Congressional mandates to PHMSA, as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition.
Our business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes which activities are subject to environmental and worker health and safety laws and regulations that may cause us to incur significant costs and liabilities.
Our business is subject to stringent federal, tribal, state, and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit or prevent emissions, discharges or releases of various materials from our pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from our 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 action obligations, suspension and debarment from federal contracting opportunities, the occurrence of delays in
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permitting and completion of projects, and the issuance of injunctive relief. For example, following a state grand jury investigation and the filing of charges alleging criminal misconduct involving the construction and related activities of the Mariner East 2 pipeline (“Mariner 2”), in August 2022 we entered into a plea of no contest with the Pennsylvania Attorney General’s Office that requires us to pay fines to the Commonwealth, pay for independent evaluations of potential water quality impacts to residential water supplies and compensate any affected homeowners, and to also pay $10 million to support water quality improvement projects. Any additional requirements from the PADEP regarding Mariner 2 or other of our pipeline projects may result in delays in the completion of these projects. Subsequently, the EPA issued a Notice of Proposed Debarment (“NPD”) on October 28, 2022, arising from SPLP’s and ETC Northeast Pipeline, LLC’s nolo contendere plea agreements and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following entities were proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4) SemGroup LLC; and (5) LE GP, LLC. The NPD presently prevents the named entities from pursuing or renewing Federal government contracts or Federal financial assistance agreements. While we are engaging with the EPA to attempt to resolve the matter, at this time there can be no assurance that the EPA will not finalize a debarment applicable to the named entities for a set period of time, or expand the debarment to other Energy Transfer affiliates. Currently, none of the entities named in the NPD are party to any Federal government contracts or Federal financial assistance agreements.
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.
We may incur substantial environmental costs and liabilities because of the underlying risk arising out of our 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.
Uncertainty about the future course of regulation continues to exist following the change in U.S. presidential administrations in January 2021. Upon taking office, the Biden Administration issued an executive order directing all federal agencies to review and take action to address any federal regulations promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, several regulatory developments have occurred, but it remains unclear the degree to which this will continue . The executive order also established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group’s interim estimate of the social cost of carbon has been subject to litigation in 2022, but is in use while litigation is pending. EPA has also separately developed its own proposal for a social cost of carbon, which is significantly higher than that proposed by the Working Group. The EPA’s proposal is currently undergoing independent peer review and is not yet in use by the agency. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.
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 our operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards, and the EPA finalized its attainment/non-attainment designations in 2018, though these are subject to change. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for ozone. However, the Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. Historically, we have been able to satisfy the more stringent nitrogen oxide emission reduction requirements that affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that we will not incur material costs in the future to meet the new, more stringent ozone standard.
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Regulations under the Clean Water Act, Oil Pollution Act of 1990, as amended (“OPA”), and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires us to maintain spill prevention control and countermeasure plans at our terminal facilities with above-ground storage tanks and pipelines. In addition, OPA requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above-ground storage tanks or pipelines.
Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects us to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States.
In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.
Terminal operations and associated facilities are subject to the Clean Air Act as well as comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies.
Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the services we provide.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime, and, in the United States, President Biden has announced that he intends to pursue substantial reductions in greenhouse gas emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. In August 2022, the IRA 2022 was signed into law, which appropriates significant federal funding for renewable energy initiatives and amends the federal Clean Air Act to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The IRA 2022 imposes a methane emissions charge on sources required to report their GHG emissions to the EPA, which would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022.Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission
Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. These Subpart OOOOa standards expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In September 2020, the EPA finalized amendments to Subpart OOOOa that rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for VOCs. In addition, the rulemaking removes from the oil and natural gas category the natural gas transmission and storage segment. However, Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating
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the 2016 standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities, Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. In November 2022, the EPA released its supplemental methane proposal. Among other items, the proposal sets forth specific revisions strengthening the first nationwide emission guidelines for states to limit methane emissions from existing crude oil and natural gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. The proposal is currently subject to public comment and is expected to be finalized in 2023. Several states have also adopted, or are considering, adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations or those of our customers as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business.
At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding GHG emission reduction goals every five years beginning in 2020. Although the United States withdrew from the Agreement under the Trump administration, President Biden recommitted the United States in February 2021, and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered again in Glasgow in November 2021 at COP26 during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase-out of fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future.
President Biden’s January 2021 climate change executive order also directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs. This pause was subsequently subject to a permanent injunction in August 2022, effectively halting implementation of the leasing suspension with respect to those leases canceled or postponed prior to March 24, 2021. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. As noted above, a separate executive order issued in January 2021 established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group’s interim estimate of the social cost of carbon, $51 per ton, has been subject to litigation in 2022, but is in use while litigation is pending. It is difficult to predict how these measures may impact our business; however, any new restrictions on oil and gas permitting or leasing on federal lands could discourage new oil and gas development by our customers, which could have an adverse effect on our business.
The adoption, strengthening and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers.
There are also increasing financing risks for fossil fuel energy companies, as various investors become increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other
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sectors. Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve announced that it has joined NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. In September 2022, the Federal Reserve announced that six of the United States’ largest banks will participate in a pilot climate scenario analysis exercise, expected to be launched in early 2023, to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. While we cannot predict what polices may result from these developments, such efforts could make it more difficult for exploration and production companies and midstream companies, like us, to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business. Additionally, in March 2022 the SEC released a proposed rule requiring climate disclosures, which is expected to be finalized in early 2023. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
Climatic events in the areas in which we operate, whether from climate change or otherwise, can cause disruptions, and in some cases, delays in, or suspension of, our services. These event, including but not limited to drought, winter storms, wildfire, extreme temperatures or flooding, may become more intense or more frequent as a result of climate change and could have an adverse effect on our continued operations. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities or our customers’ facilities from powerful winds or rising waters. We may experience increased insurance costs, or difficulty obtaining adequate insurance coverage, for our assets in areas subject to more frequent severe weather. We may not be able to recoup these increased costs through the rates we charge our customers. Extreme weather events could cause damage to property or facilities that could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected.
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 transport, and thus demand for our services. 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.
A climate-related decrease in demand for crude oil, natural gas and other hydrocarbon products could negatively affect our business.
Supply and demand for crude oil, natural gas and other hydrocarbon products we handle is dependent upon a variety of factors, many of which are beyond our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil, natural gas and other hydrocarbon products, thereby potentially causing a reduction in the demand for such products. A broader transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes, governmental incentives and funding such as those provided in the IRA 2022, or consumer preferences could result in decreased demand for hydrocarbon products like crude oil, natural gas and NGLs that we handle. Any decrease in demand for these products could consequently reduce demand for our services and could have a negative effect on our business.
Increased attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to, and societal expectations on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and consequently demand for our midstream services, reduced profits, increased risk of investigations and litigation, and negative impacts on the value of our assets and access to capital. Increasing attention to climate change and environmental conservation, for example, may result in reduced demand for oil and natural gas products and additional governmental investigations and private litigation against us or our customers. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed
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without regard to our causation of or contribution to climate change or asserted damage to the environment, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our ESG profile. Moreover, while we are pursuing various low-carbon opportunities such as renewable power generation, renewable fuels, and carbon capture and storage projects through our alternative energy initiatives to address potential energy transition related risks, we cannot guarantee that we will be able to execute these projects in a timely manner because of permitting, technology, or other risks or that such opportunities will ultimately be successful.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on expectations and assumptions. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent that we do meet such targets, we may consider the acquisition of various credits or offsets that may be deemed to assist in the achievement of such targets or otherwise mitigate our ESG impact instead of actual achievements of such targets or actual changes in our ESG performance. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a designated contract markets or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and other related developments may have a material adverse effect on our business, financial condition, or results of operations.
The Federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the DOI, 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
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difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. For instance, in January 2021, the Biden Administration issued an executive order focused on climate change that, among other things, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs.
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 our customers. Separately, in October 2020, BOEM and BSEE published a proposed rule regarding financial assurance requirements for offshore leases, particularly regarding requirements for bonds above base amounts prescribed by regulation. At this time, we cannot determine with any certainty the amount of any additional financial assurance that may be ordered by BOEM and required of us in the future, or that such additional financial assurance amounts can be obtained. The final publication or implementation of this rule, 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 our 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. Separately, in January 2021, the Biden Administration issued orders temporarily suspending the issuance of new authorizations and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021 and permanent injunction in August 2022, effectively halting implementation of the leasing suspension. Additionally, provisions in the IRA 2022 require that particular offshore oil and gas lease sales under the 2017 – 2022 leasing program proceed, and the DOI has reinstated or announced plans for those sales. In July 2022, the DOI published a proposed offshore leasing program for 2023 – 2028, although the approval process is ongoing and may be subject to change or challenge. Relatedly, the DOI released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. Implementation of many of the recommendations in the DOI report will require Congressional action and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and adversely impact our business and adversely impact our business. The Biden Administration also published an order calling for an increase in the production of offshore wind energy, which may impact the use of federal waters. We cannot predict with any certainty the full impact of any new laws or regulations on our 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 our services, which could have a material adverse effect on our business as well as our financial position, results of operation and liquidity.
Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, our patented butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.
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Risks Relating to Our Partnership Structure
Issuance of Common Units or Other Classes of Equity
We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
Our Partnership Agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:
•our Unitholders’ current proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each Common Unit or partnership security may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding Common Unit and/or Preferred Unit may be diminished; and
•the market price of our Common Units and/or Preferred Units may decline.
Cash Distributions to Unitholders and Governance
Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.
The amount of cash we can distribute to our Unitholders depends upon the amount of cash we generate from our operations and from our subsidiaries, Sunoco LP and USAC. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other things:
•the amount of natural gas, NGLs, crude oil and refined products transported in our pipelines;
•the level of throughput in our processing and treating operations;
•the fees we charge and the margins we realize for our services;
•the price of natural gas, NGLs, crude oil and refined products;
•the relationship between natural gas, NGL and crude oil prices;
•the weather in our operating areas;
•the level of competition from other midstream, transportation and storage and other energy providers;
•the level of our operating costs;
•prevailing economic conditions; and
•the level and results of our derivative activities.
In addition, the actual amount of cash we and our subsidiaries, including Sunoco LP and USAC, will have available for distribution will also depend on other factors, such as:
•the level of capital expenditures we and our subsidiaries make;
•the level of costs related to litigation and regulatory compliance matters;
•the cost of acquisitions, if any;
•the levels of any margin calls that result from changes in commodity prices;
•our and our subsidiaries’ debt service requirements;
•fluctuations in our and our subsidiaries’ working capital needs;
•our and our subsidiaries’ ability to borrow under our revolving credit facility;
•our and our subsidiaries’ ability to access capital markets;
•restrictions on distributions contained in our and our subsidiaries’ debt agreements; and
•the amount of cash reserves established by our general partner in its discretion for the proper conduct of our business.
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Because of all these factors, 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.
Furthermore, our Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, we may declare and/or pay cash distributions during periods when we record net losses.
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to Unitholders.
Our Partnership Agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our Partnership Agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to Unitholders.
Unitholders may have liability to repay distributions.
Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to the limited partnership for the distribution amount for three years from the distribution date.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.
Our common and series C, D and E preferred units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, our Unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.
Our General Partner
The control of our general partner may be transferred to a third party without Unitholder consent.
Our general partner may transfer its general partner interest to a third party without the consent of the Unitholders. Any new owner of the general partner would be in a position to replace the officers and directors of the general partner with its own designees and thereby exert significant influence over the decisions made by such officers and directors.
The majority owner of our general partner has rights that protect him against dilution.
Through his controlling interest in our general partner, Kelcy Warren owns all of the outstanding Energy Transfer Class A Units, which represents an approximately 20% voting interest in the Partnership. Under the terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to the general partner additional Energy Transfer Class A Units such that Mr. Warren maintains a voting interest in the Partnership that is equivalent to his voting interest in the Partnership with respect to such Energy Transfer Class A Units (approximately 20%) prior to such issuance of common units. As a result, Mr. Warren is partially protected against the dilutive effect of additional common unit issuances by the Partnership with respect to voting. As of December 31, 2022, the Partnership had outstanding 765,896,700 Energy Transfer Class A Units.
Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay the distributions to Unitholders.
Prior to making any distributions to our Unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the Unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.
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Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our Unitholders have no right to elect our general partner or the board of directors of our general partner. Our general partner has the right to appoint and replace the members of the board, including all of its independent directors. Mr. Warren owns an 81.2% membership interest in our general partner and controls our general partner and therefore has the ability to direct our general partner with respect to the exercise of these governance rights.
If our Unitholders are dissatisfied with the general partner’s performance, they have limited ability to remove the general partner. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the general partner; however, Mr. Warren owns a significant number of common units and, through his controlling interest in the general partner, owns all of the outstanding Energy Transfer Class A Units, which vote together with the common units and entitle the holders of the Energy Transfer Class A Units to maintain the voting percentage in Energy Transfer represented by such Energy Transfer Class A Units as of the date the initial Energy Transfer Class A Units were issued (approximately 20%) any time new common units are issued. As of February 16, 2023, Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%. As a result of this and other limitations, it may be more difficult to remove the general partner.
Furthermore, our Partnership Agreement contains provisions limiting the ability of common unitholders to call meetings or to obtain information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management. Common unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to our common units, the general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such common units with the prior approval of the general partner, cannot vote on any matter.
Kelcy Warren owns a majority interest in, and controls, our general partner, and our general partner has sole responsibility for conducting our business and managing our operations. The general partner may have conflicts of interest with us and limited fiduciary duties, and it may favor its own interests to the detriment of us and our Unitholders.
Mr. Warren owns an 81.2% membership interest in, and therefore controls, the general partner and accordingly has the right to appoint and replace all of the officers and directors of the general partner. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our Unitholders, the directors and officers of the general partner also have a fiduciary duty to manage the general partner in a manner that is beneficial to its majority owner, Mr. Warren. Conflicts of interest will arise between the general partner and its owner, on the one hand, and us and our Unitholders, on the other hand. In resolving these conflicts of interest, the general partner may favor its own interests and the interests of its owner over our interests and the interests of our Unitholders.
Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Under Delaware law, an assignee who becomesunitholders could be held liable for our obligations to the same extent as a substitutedgeneral partner if a court determined that the right of limited partners to remove our general partner or to take other action under the Partnership Agreement constituted participation in the “control” of our business. Additionally, under Delaware law, our general partner has unlimited liability for the obligations of Energy Transfer, such as our debts and environmental liabilities, except for those contractual obligations of Energy Transfer that are expressly made without recourse to the general partner.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership is liablehave not been clearly established in some of the states in which we do business. Unitholders could have unlimited liability for the obligations of the assignorPartnership if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) a Unitholder’s right to make contributionsact with other Unitholders to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she becamePartnership Agreement constituted “control” of our business.
Our general partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our general partner ifand its affiliates own more than 90% of our outstanding units, our general partner will have the liabilities couldright, 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 determined fromrequired to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may
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also incur a tax liability upon a sale of their units. As of December 31, 2022, the partnership agreement.directors and executive officers of our general partner owned approximately 11% of our Common Units.

Our Subsidiaries
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. In particular, our Five-Year Credit Facility (as defined herein), limits our and certain of our subsidiaries’ ability to make distributions. 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.
UnitholdersThe interruption of distributions to us from our operating subsidiaries and equity investees may affect our ability to satisfy our obligations and to make distributions to our partners.
We are a holding company with no business operations other than that of our operating subsidiaries. Our only significant assets are the equity interests we own in our operating subsidiaries and equity investees. As a result, we depend upon the earnings and cash flow of our operating subsidiaries and equity investees and any interruption of distributions to us may affect our ability to meet our obligations, including any obligations under our debt agreements, and to make distributions to our partners.
Our subsidiaries are not prohibited from competing with us.
Neither our Partnership Agreement nor the partnership agreements of our subsidiaries, including Sunoco LP and USAC, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Sunoco LP and USAC may issue additional common units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.
The partnership agreements of Sunoco LP and USAC allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:
•unitholders’ current proportionate ownership interest in each partnership will decrease;
•the amount of cash available for distribution on each common unit or partnership security may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding common unit may be diminished; and
•the market price of each partnership’s common units may decline.
The payment of distributions on any additional units issued by Sunoco LP and USAC may increase the risk that either partnership may not have limited liability if a court findssufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that unitholder actions constitute control ofwe have to meet our business.obligations
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 participationA reduction 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 forSunoco LP’s distributions will disproportionately affect the amount of a distribution for a period of three years from the datecash distributions to which Energy Transfer is entitled.
Energy Transfer indirectly owns all of the distribution.incentive distribution rights (“IDRs”) of Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by Sunoco LP as such entity reaches established target cash distribution levels as specified in its partnership agreement. Energy Transfer currently receives its pro rata share of cash distributions from Sunoco LP based on the highest sharing level of 50% in respect of the Sunoco LP IDRs.
Our debt level and debt agreements may limit ourA decrease in the amount of distributions by Sunoco LP to less than $0.65625 per unit per quarter would reduce Energy Transfer’s percentage of the incremental cash distributions from Sunoco LP above $0.546875 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that Energy Transfer receives, based on its ownership interest in the IDRs as compared to cash distributions received from its Sunoco LP common units.
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A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency, in the areas Sunoco LP serves would reduce their ability to make distributions to Unitholdersits unitholders.
For the year ended December 31, 2022, sales of refined motor fuels accounted for approximately 98% of Sunoco LP’s total revenues and 72% of gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and Sunoco LP’s ability to make distributions to its unitholders, including Energy Transfer. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.
Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers’ shopping habits or lead to new forms of fueling destinations or new competitive pressures.
New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased demand for petroleum-based fuel. Any of these outcomes could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.
Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.
The industries in which Sunoco LP operates are subject to seasonal trends, which may cause its operating costs to fluctuate, affecting its cash flow.
Sunoco LP relies in part on customer travel and spending patterns and may limit our future financialexperience more demand for gasoline in the late spring and operating flexibilitysummer months than during the fall and may require asset sales.
As of December 31, 2017, we had approximately $6.70 billion of debt on a stand-alone basiswinter. Travel, recreation and approximately $44.08 billion of consolidated debt, excludingconstruction are typically higher in these months in the debtgeographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:
fiscal year. As a significant portion of our and our subsidiaries’ cash flowresult, Sunoco LP’s results from operations will be dedicatedmay vary widely from period to period, affecting Sunoco LP’s cash flow.
The dangers inherent in the paymentstorage and transportation of principalmotor fuel could cause disruptions in Sunoco LP’s operations and interestcould expose them to potentially significant losses, costs or liabilities.
Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a
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material adverse effect on outstanding debtits business, financial condition, results of operations and will not becash available for other purposes, including payment of distributions;distribution to its unitholders.
covenants contained in ourSunoco LP’s fuel storage terminals are subject to operational and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests thatbusiness risks which may adversely affect our flexibility in planning for and reacting to changes in our business;
our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
we may be at a competitive disadvantage relative to similar companies that have less debt;
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.
In order for us to manage our debt levels, we may need to sell assets, issue additional equity securities, reduce the cash distributions we pay to our unitholders or a combination thereof. In the event that we sell assets, the future cash generating capacity of our remaining asset base may be diminished. In the event that we issue additional equity securities, we may need to issue these securities at a time when our common unit price is depressed and therefore we may not receive favorable prices for our common units or favorable prices or terms for other types of equity securities. In the event we reduce cash distributions on our common units, the public trading price of our common units could decline significantly.
Our General Partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2017, the directors and executive officers of our General Partner owned approximately 27% of our Common Units.

Litigation commenced by WMB against ETE and its affiliates could cause ETE to incur substantial costs, may present material distractions and, if decided adverse to ETE, could negatively impact ETE’s financial position and credit ratings.
WMB filed a complaint against ETE and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates.  Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ETE on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware.  WMB filed an amended complaint on September 16, 2016 and seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement. The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by WMB’s misconduct. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that WMB breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, WMB filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on WMB’s motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.  On January 11, 2017, the parties held oral argument before the Delaware Supreme Court on WMB’s appeal of the June 24 ruling. The Delaware Supreme Court has taken the matter under advisement. These lawsuits could result in substantial costs to ETE, including litigation costs and settlement costs. ETE believes that the time required by the management of ETE and its counsel to defend against the allegations made by WMB in the litigation against ETE and its affiliates is likely to be substantial and the time required by the officers and employees of LE GP, assuming WMB actively pursues such litigation, is also likely to be substantial. The defense or settlement of any lawsuit or claim that remains unresolved may result in negative media attention, and may adversely affect ETE’s business, reputation, financial condition, results of operations, cash flows and ability to make distributions to its unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:
•the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;
•the dependence on third parties to supply their fuel storage terminals;
•outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;
•the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;
•the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;
•the effects of a sustained recession or other adverse economic conditions;
•the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;
•competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and
•climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.
The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to its unitholders.
Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.
Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market price.value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to its unitholders.
The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.
The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could
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attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.
In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to its unitholders.
Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.
Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.
It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.
Sunoco LP does not own all of the land on which its retail service stations are located, and Sunoco LP leases certain facilities and equipment, and Sunoco LP is subject to the possibility of increased costs to retain necessary land use which could disrupt its operations.
Sunoco LP does not own all of the land on which its retail service stations are located. Sunoco LP has rental agreements for approximately 35% of the company, commission agent or dealer operated retail service stations where Sunoco LP currently controls the real estate. Sunoco LP also 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.
Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.
New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (“RFS”) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINs”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have
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to utilize the RINs it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINs to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline. In addition, the RFS regulations are highly complex and evolving, and the RINs market is subject to significant price volatility as a result. In December 2022, the EPA released a proposed rule under the RFS for renewable fuel volumes for the years 2023-2025 that further increases targets for the production of renewable fuels. Subject to certain limitations, EPA now has significant discretion to set renewable fuel targets under the RFS, which could result in increased compliance obligations on refiners and importers and transportation fuels. The price of RINs to meet compliance obligations under the RFS could be substantial and adversely impact our financial condition.
The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.
Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.
USAC’s customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.
USAC’s customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using USAC’s compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units more affordable to USAC’s customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and USAC’s customers may elect to use these alternative technologies instead of the gas lift compression services USAC provides. Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for USAC’s compression services, which may have a material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution.
A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.
USAC’s contracts typically have initial terms between six months to five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by USAC or USAC’s customers upon notice as provided for in the applicable contract. For the year ended December 31, 2022, approximately 29% of USAC’s compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on USAC’s business, results of operations, financial condition and cash available for distribution.
USAC’s preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.
USAC’s preferred units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for its common units or could make it more difficult for USAC to sell its common units in the future.
In addition, distributions on USAC’s preferred units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per preferred unit. If USAC does not pay the required distributions on its preferred units, USAC will be unable to pay distributions on its common units. Additionally, because distributions on USAC’s preferred units are cumulative, USAC will have to pay all unpaid accumulated distributions on the preferred units before USAC can pay any distributions on its common units. Also, because distributions on USAC’s common
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units are not cumulative, if USAC does not pay distributions on its common units with respect to any quarter, USAC’s common unitholders will not be entitled to receive distributions covering any prior periods if USAC later recommences paying distributions on its common units.
USAC’s preferred units are convertible into common units by the holders of USAC’s preferred units or by USAC in certain circumstances. USAC’s obligation to pay distributions on USAC’s preferred units, or on the common units issued following the conversion of USAC’s preferred units, could impact USAC’s liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general Partnership purposes. USAC’s obligations to the holders of USAC’s preferred units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.
Risks Related to Conflicts of Interest
The fiduciary duties of our general partner’s officers and directors may conflict with those of Sunoco LP’s or USAC’s respective general partners.
Conflicts of interest may arise because of the relationships among Sunoco LP, USAC, their general partners and us. Our General Partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our general partner’s directors or officers are also directors and/or officers of Sunoco LP’s general partner or USAC’s general partner, and have fiduciary duties to manage the respective businesses of Sunoco LP and USAC in a manner beneficial to Sunoco LP, USAC and their respective unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
Although we control ETPSunoco LP and Sunoco LPUSAC through our ownership of theirSunoco LP’s and USAC’s general partners, ETP’sSunoco LP’s and Sunoco LP’sUSAC’s general partners owe fiduciary duties to ETP and ETP’s unitholders and Sunoco LP and Sunoco LP’s unitholders and USAC and USAC’s unitholders, respectively, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETPSunoco LP and Sunoco LPUSAC and their respective limited partners, on the other hand. The directors and officers of ETP’s and Sunoco LP’s General Partnersand USAC’s general partners have fiduciary duties to manage ETPSunoco LP and Sunoco LP,USAC, respectively, in a manner beneficial to us. At the same time, the General Partnersgeneral partners have fiduciary duties to manage ETPSunoco LP and Sunoco LPUSAC in a manner beneficial to ETPSunoco LP and Sunoco LPUSAC and their respective limited partners. The boards of directors of ETP’s and Sunoco LP’s General Partnerand USAC’s general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
For example, conflicts of interest with ETPSunoco LP and Sunoco LPUSAC may arise in the following situations:
•the allocation of shared overhead expenses to ETP, Sunoco LP, USAC and us;
•the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETPSunoco LP and Sunoco LP,USAC, on the other hand;
•the determination of the amount of cash to be distributed to ETP’sSunoco LP’s and Sunoco LP’sUSAC’s partners and the amount of cash to be reserved for the future conduct of ETP’s and Sunoco LP’s and USAC’s businesses;
•the determination whether to make borrowings under ETP’sSunoco LP’s and Sunoco LP’sUSAC’s revolving credit facilities to pay distributions to their respective partners;
•the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETPSunoco LP and Sunoco LPUSAC is made available for ETPSunoco LP and Sunoco LPUSAC to pursue; and
•any decision we make in the future to engage in business activities independent of ETP and Sunoco LP.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
The petroleum products that we store and transport through ETP’s operations are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.
Our business could be affected adversely by union disputes and strikes or work stoppages by Panhandle’s and Sunoco LP’s unionized employees.
As of December 31, 2017, approximately 5% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that Panhandle or Sunoco, Inc. will not experience a work stoppagearise in the future as a result of labor disagreements. Any work stoppage could, dependingthe relationships between us and our affiliates, on the affected operationsone hand, and Sunoco LP and USAC and their respective limited partners, on the other hand. The directors and officers of Sunoco LP’s and USAC’s general partners have duties to manage Sunoco LP and USAC, respectively, in a manner beneficial to us. At the same time, the general partners have fiduciary duties to manage Sunoco LP and USAC in a manner beneficial to Sunoco LP and USAC and their respective limited partners. The boards of directors of Sunoco LP’s and USAC’s general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations:
•the allocation of shared overhead expenses to Sunoco LP, USAC and us;
•the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other hand;
•the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the lengthamount of cash to be reserved for the work stoppage, havefuture conduct of Sunoco LP’s and USAC’s businesses;
•the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners;
•the determination of whether a material adverse effect on our business financial position, results of operationsopportunity (such as a commercial development opportunity or cash flows.
Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on our retail marketing business.
Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require us to incur additional capital expenditures or expenses particularly in our retail marketing business. We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in marketsan acquisition) that we supply. In addition, a significant shift by consumersmay become aware of independently of Sunoco LP and USAC is made available for Sunoco LP and USAC 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,pursue; and reduced margins, for the refined petroleum products that
•any decision we market and sell.
It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco, Inc.’s business or results of operations.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

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

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

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

Unitholders may beare required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which will be different in amount than the cash we distribute, our unitholders will beOur Unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even ifwhether or not they receive no cash distributions from us. Our unitholdersUnitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that resultresults from that income.
Tax gain or loss on disposition of our Common Unitsunits could be more or less than expected.
If our unitholders sella Unitholder sells their common units, theythe Unitholder will recognize a gain or loss equal to the difference between the amount realized and theirthat Unitholder’s tax basis in those common units. PriorBecause distributions to our unitholders in excess of the totala Unitholder’s allocable share of our net taxable income the unitholder was allocated for a unit, which decreased theirdecrease such Unitholder’s tax basis in that unit,their units, the amount, if any, of such prior excess distributions with
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respect to the units a Unitholder sells will, in effect, become taxable income to our unitholdersa Unitholder if the common unit issuch units are sold at a price greater than their tax basis in that common unit,those units, even if the price they receivesuch Unitholder receives is less than their original cost. A substantial portion ofcosts. In addition, because the amount realized whether or not representing gain, may be ordinary income. In addition,includes a Unitholder’s share of our nonrecourse liabilities, if our unitholders sella Unitholder sells their units, theya Unitholder may incur a tax liability in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from a Unitholder’s sale of their units, whether or not representing gain, may be taxed as ordinary income to such Unitholder due to potential recapture items, including depreciation recapture. Thus, a Unitholder may recognize both ordinary income and capital loss from the sale of Common Units if the amount realized on a sale of such units is less than such Unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a Unitholder sells their units, such Unitholder may recognize ordinary income from our allocations of income and gain to such Unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, includingsuch as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to Unitholders whoorganizations that are organizations exempt from United States federal income tax, including IRAs and other retirement plans, will be “unrelatedunrelated business taxable income”income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-United States unitholdersUnitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our unitholdersUnitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business. As a result, distributions to a Non-Unitednon-United States unitholderUnitholder will be subject to withholding at the highest applicable effective tax rate and a Non-Unitednon-United States unitholderUnitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit. 
The Tax CutsIn addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. We intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and Jobs Act imposessubject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding obligation of 10%tax rate equal to the sum of the amount realized upon a Non-United States unitholder’s sale or exchangehighest applicable effective tax rate and 10%.
Moreover, the transferee of an interest in a partnership that is engaged in a United States trade or business. However, duebusiness is generally required to challengeswithhold 10% of administeringthe “amount realized” by the transferor unless the transferor certifies that it is not a withholding obligationforeign person. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to open market trading and other complications, the IRS has temporarily suspended the applicationany decrease in that partner’s share of this withholding rule to open market transfersa publicly traded partnership’s liabilities. For a transfer of interests in a publicly traded partnerships pending promulgation of regulationspartnership that is effected through a broker on or other guidance that resolvesafter January 1, 2023, the challenges.  Itobligation to withhold is not clear if or when such regulations or other guidance will be issued.  Non-United Statesimposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult atheir tax advisor before investingadvisors regarding the impact of these rules on an investment in our units.
We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations are conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders.Unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

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

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Unitholders will likely be subject to state and local taxes and income tax return filing requirements in statesjurisdictions where they do not live as a result of investing in our units.
In addition to United States federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. Unitholders maywill likely be required to file state and local income tax returns and pay state and local income taxes in some or all of thethese various jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, our unitholdersUnitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is generally limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income.
Treatment of distributions on Energy Transfer Preferred Units as guaranteed payments for the use of capital is uncertain and such distributions may not be eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of distributions on our Preferred Units is uncertain. We will treat Preferred Unitholders as partners for tax purposes and will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to Preferred Unitholders as ordinary income. Preferred Unitholders will recognize taxable income andfrom the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution). Otherwise, except in the case of taxable years beginning before January 1, 2022,our liquidation, Preferred Unitholders are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any deduction allowableshare of our nonrecourse liabilities to Preferred Unitholders. If the Energy Transfer Preferred Units were treated as indebtedness for depreciation, amortization, or depletion. tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to Preferred Unitholders.
Although the interest limitation does not apply to certain regulated pipeline businesses, applicationwe expect that much of the interest limitationincome we earn will be eligible for the 20% deduction for qualified publicly traded partnership income, the Treasury Regulations provide that income attributable to tiered businesses like ours that hold interests in regulated and unregulated businessesa guaranteed payment for the use of capital is not clear. Pending further guidance specificeligible for the 20% deduction for qualified business income. As a result income attributable to this issue, we havea guaranteed payment for use of capital recognized by holders of our Preferred Units is not yet determinedeligible for the impact20% deduction for qualified business income.
A Preferred Unitholder will be required to recognize gain or loss on a sale of Energy Transfer Preferred Units equal to the limitation could havedifference between the amount realized by such Preferred Unitholder and such Preferred Unitholder’s tax basis in the Energy Transfer Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such Preferred Unitholder receives in exchange for such Energy Transfer Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the Preferred Unitholder to acquire such Energy Transfer Preferred Units. Gain or loss recognized by a Preferred Unitholder on the sale or exchange of Energy Transfer Preferred Units held for more than one year generally will be taxable as long-term capital gain or loss. Because Preferred Unitholders will generally not be allocated a share of our unitholders’ ability to deduct our interest expense, butitems of depreciation, depletion or amortization, it is possiblenot anticipated that such Preferred Unitholders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in our unitholders’ interest expense deductionPreferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-United States persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes. Distributions to non-United States Preferred Unitholders will be limited.subject to withholding taxes. If the amount of withholding exceeds the amount of United States federal income tax actually due, non-United States Preferred Unitholders may be required to file United States federal income tax returns in order to seek a refund of such excess.
All Preferred Unitholders are urged to consult a tax advisor with respect to the consequences of owning Energy Transfer Preferred Units.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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ITEM 2. PROPERTIES
A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania andPennsylvania; Houston, Corpus ChristiTexas and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
Substantially all of our subsidiaries’ pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. Our subsidiariesWe 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. ETPWe also ownsown and operatesoperate multiple natural gas and NGL storage facilities and ownsown or leaseslease other processing, treating and conditioning facilities in connection with itsour midstream operations.
ITEM 3. LEGAL PROCEEDINGS
Sunoco, Inc. and/For information regarding legal proceedings, Note 11 in “Item 8. Financial Statements and Supplementary Data” in this Annual Report on Form 10-K for the year ended December 31, 2022.
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 Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other membersprotection of the petroleum industry,environment. While we believe that even if any one or more of the following environmental proceedings 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 reasonably could result in monetary sanctions in excess of $0.3 million.
ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices.practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2017,2022, Sunoco Inc. is a defendantDefendants are defendants in sevenfour cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico.

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

determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. In response, FERC authorized Rover to resume HDD activities at certain sites. On January 24, 2018, FERC ordered Rover to cease HDD activities at the Tuscarawas River HDD site pending FERC review of additional information from Rover. Rover continues to correspond with regulators regarding drilling operations and drilling plans at the HDD sites where Rover has not yet completed HDD activities, including the Tuscarawas River HDD site. The timing or outcome of this matter cannot be reasonably determined at this time. We do not expect there to be a material impact to its results of operations, cash flows or financial position.
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of Rover’s demolition ofa potentially historic home (known as the Stoneman House, a potential historic structure, in connection withHouse) while Rover’s application for permission to construct athe new 711-mile interstate natural gas pipeline and related facilities.facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. On January 25, 2022, the chief judge assigned an administrative law judge and set a timeline for a prehearing conference.
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On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of Texas seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the federal district court case. On May 24, 2022, the District Court ordered a stay of the FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. Energy Transfer and Rover intend to vigorously defend this claim.
In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and ETPthe Partnership are cooperating with the investigation. In March and April 2017, Enforcement Staff has provided Rover its non-public preliminary findings regarding its investigation.with a notice pursuant to Section 1b.19 of the FERC’s regulations that Enforcement Staff intends to recommend that the FERC pursue an enforcement action against Rover and the Partnership. The company disagrees with thoseEnforcement Staff’s findings and intends to vigorously defend against any potential penalty. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover to show cause why it should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. Any and all losses, including any fines and penalties from government agencies, resulting from the general contractor’s alleged actions in conducting such HDD operations are subject to indemnity rights in favor of Rover and the Partnership. Given the stage of the proceeding,proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.
On November 3, 2017, the State of Ohio and the non-public natureOhio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District court of appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the preliminary findingsClean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver. On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. Briefing on those motions was completed on November 4, 2022. The motions remain pending before the court.
The PA AG commenced an investigation ETPregarding the Incident, and the United States Attorney for the Western District of Pennsylvania issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.
On February 2, 2022, the PA AG issued a press release related to the Revolution pipeline, and released a Grand Jury Presentment and filed a criminal complaint against ETC Northeast Pipeline, LLC in Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania, with respect to nine misdemeanor charges related to various alleged violations of the Clean Streams Law associated with the construction of the Revolution pipeline.
On August 5, 2022, the PA AG held a press conference to announce that the matter had been resolved through an agreement whereby ETC Northeast Pipeline, LLC and SPLP entered a plea of no contest to all charges. The resolution also included terms that ETC Northeast Pipeline, LLC would pay an approximate $23 thousand fine to the Clean Water Fund at the Pennsylvania Department of Environmental Protection and SPLP would pay a $35 thousand fine to the Clean Water Fund at the Pennsylvania Department of Environmental Protection. Additionally, both companies would jointly establish a fund of approximately $0.4 million to create a Homeowner Well Water Supply Grievance Program and pay $10 million to support water quality improvement projects. The plea agreement was entered by court on August 12, 2022, and the matter is now closed.
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In January 2019, we received notice from the DOJ on behalf of the EPA that a civil penalty enforcement action was being pursued under the Clean Water Act for an estimated 450 barrel crude oil release from the Mid-Valley Pipeline operated by SPLP and owned by Mid-Valley. The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete. Operation and maintenance (O&M) activities will continue for several years. In December of 2019, SPLP reached an agreement in principal with the EPA regarding payment of a civil penalty which will be subject to public comment. The DOJ, on behalf of United States Department of Interior Fish and Wildlife, and the Ohio Attorney General, on behalf of the Ohio EPA, along with technical representatives from those agencies have resolved in principal the natural resource damage assessment claims related to state endangered species and compensatory restoration.
On October 28, 2022, the EPA issued a Notice of Proposed Debarment (“NPD”) arising from SPLP’s and ETC Northeast Pipeline, LLC’s nolo contendere plea agreements and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following entities were proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4) SemGroup LLC; and (5) LE GP, LLC. The NPD presently prevents the named entities from pursuing or renewing Federal government contracts or Federal financial assistance agreements. We are engaging with the EPA to address the EPA’s concerns. Currently, none of the entities named in the NPD are party to any Federal government contracts or Federal financial assistance agreements.
In July 2021, Energy Transfer LP, Energy Transfer R&M and certain of their affiliates were named as parties in a complaint filed by the Ohio Petroleum Underground Storage Tank Release Compensation Board (“PUSTRCB”) to recover over $8.5 million paid by PUSTRCB to Energy Transfer R&M or on Energy Transfer R&M’s behalf due to alleged false, misleading and/or fraudulent representations. Specifically, in 1996, Energy Transfer R&M filed a lawsuit in the Superior Court of California (Los Angeles City) against its historic Commercial General Liability (“CGL”) insurers, excess and re-insurers entitled Jalisco et al. v. Argonaut et al. (“Jalisco”) - Case No. BC158441 - seeking a declaration of coverage under insurance policies which had been in place before 1986. The Jalisco action included refineries, Superfund sites, oil fields, pipelines, and service stations, among other sites, and the lawsuit was ultimately settled with the insurers. Sunoco, Inc. received reimbursement from PUSTRCB for costs incurred at service stations located in Ohio, and PUSTRCB now claims that Sunoco, Inc. failed to disclose to PUSTRCB the claims asserted against its insurers, the Jalisco action and the settlements and failed to repay the monies received from PUSTRCB. PUSTRCB seeks compensatory damages, restitution and disgorgement, punitive damages, interest and attorney’s fees. A $3.2 million settlement was agreed upon in December 2022, and the matter was resolved and dismissed in January 2023 without admission of responsibility.
On February 3, 2022, the State of New Mexico, ex rel. Hector Balderas, Attorney General filed a Complaint against ETO, Transwestern, Kinder Morgan, Inc., El Paso Natural Gas LLC, and Northwest Pipeline, LLC in Cause No. D-101-CV-2022-00174 in the First Judicial District Court, County of Santa Fe, State of New Mexico, seeking to recover statewide damages for contamination with PCBs used for decades by the oil and gas industry in the operation and maintenance of pipeline infrastructure. The complaint alleges discharge or release of PCBs into the natural environment from compressor stations in connection with the operation of the Transwestern Pipeline. Given the early stage of this proceeding, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.
On July 25, 2017,June 29, 2022, near Henderson, Tennessee, a Mid Valley Pipeline Company mowing contractor struck an exposed section of the Pennsylvania Environmental Hearing Board (“EHB”) issued22-inch diameter Hornsby to Denver line segment while mowing. The brush cutter mowing implement cut open the pipeline and released an order to SPLP to cease HDDestimated 4,345 barrels of crude oil into the surrounding area. Approximately 3,343 barrels of crude oil were recovered during initial remediation activities with the remaining volume contained within the materials removed and disposed of in Pennsylvania relatedaccordance with applicable environmental laws and regulations. Corrective action is being completed pursuant to the Mariner East 2 project.  The EHB issuedTennessee DEC’s Division of Remediation - Voluntary Action Program. No injuries resulted from the order in response toincident. Mid Valley received a complaint filed by environmental groups against SPLP andNotice of Federal Interest regarding the Pennsylvania Department of Environmental Protection (“PADEP”).  On August 10, 2017 the parties reached a final settlement requiring that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.
In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreementsincident and has been authorized by PADEP to resume drillingalso supplied PHMSA with information as requested. No other government agency action has occurred at one of the three locations.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
On January 18, 2018, PHMSA issued a NOPV and a Proposed Civil Penalty in connection with alleged violations on ETP’s East Boston jet fuel pipeline in Boston, MA. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
On January 18, PHMSA issued a NOPV and a PCO in connection with alleged violations on Eastern Area refined products and crude oil pipeline system in the States of MI, OH, PA, NY, NJ and DE. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

this time.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.$300,000.
For a description of other legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
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ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

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

(1)
Distributions are shown in the quarter with respect to which they relate. Please see “Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.
Description of Units
As of February 16, 2018,10, 2023, there were approximately 158,922 individual common unitholders, which includes12,000 holders of record of our common units, heldwhich number does not separately account for individual participants in street name.securities positions listings. Common units represent limited partner interestinterests in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of LimitedEnergy Transfer’s Partnership as amended to date (the “Partnership Agreement”).Agreement.
As of December 31, 2017,2022, limited partners own an aggregate 94.4%99.9% limited partner interest in us. Our General Partner owns an aggregate 0.2% General Partner0.1% general partner interest in us. Our common units are registered under the Securities Exchange Act, of 1934, as amended (the “Exchange Act”), and are listed for trading on the NYSE.NYSE under the ticker symbol “ET.” Each holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common units are entitled to distributions of Available Cash as described below underin “Cash Distribution Policy.”
On March 8, 2016,Energy Transfer Class A Units
As of February 10, 2023, the Partnership completed a private offering of 329.3 million Serieshad outstanding 765,933,429 Class A Convertible Preferred Unitsunits (“Energy Transfer Class A Units”) representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who electedthe General Partner. The Energy Transfer Class A Units are entitled to participate in a plan to forgo a portion of their future potential cash distributions onvote together with the Partnership’s common units, participatingas a single class, except as required by law. Additionally, Energy Transfer’s Partnership Agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of Energy Transfer Class A Units additional Energy Transfer Class A Units such that the holder maintains a voting interest in the plan for a period of upPartnership that is identical to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributionsits voting interest in the Convertible Units. With respect to each quarter for which the declaration date and record date occursPartnership prior to such issuance of common units. The Energy Transfer Class A Units are not entitled to distributions and otherwise have no economic attributes.
Energy Transfer Preferred Units
The Partnership currently has the closingfollowing series of preferred units outstanding:
Series of Preferred UnitsUnits Issued and OutstandingLiquidation Preference per Unit
Date Issued(1)
6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units950,000$1,000 April 2021
6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units550,0001,000 April 2021
7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units18,000,00025 April 2021
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units17,800,00025 April 2021
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units32,000,00025 April 2021
6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units500,0001,000 April 2021
7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units1,484,7801,000 
April 2021 and December 2021(2)
6.500% Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units900,0001,000 June 2021
(1)In connection with the merger, or earlier terminationRollup Mergers on April 1, 2021, as discussed in Note 1 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data,” all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with identical distribution and redemption rights.
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(2)In connection with the merger agreement (the “WMB End Date”), each participating common unit will receiveEnable Acquisition in December 2021, Energy Transfer issued 384,780 additional Series G Preferred Units. The total reflected above includes these additional Series G Preferred Units, as well as the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of1,100,000 Series G Preferred Units originally issued in the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, onRollup Mergers.

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

 Years Ended December 31,
 2017 2016* 2015* 2014* 2013*
Statement of Operations Data:         
Total revenues$40,523
 $31,792
 $36,096
 $54,435
 $48,335
Operating income2,713
 1,843
 2,287
 2,389
 1,587
Income from continuing operations2,543
 462
 1,023
 1,014
 318
Income (loss) from discontinued operations(177) (462) 38
 60
 33
Net Income2,366
 —
 1,061
 1,010
 351
Basic income from continuing operations per limited partner unit0.86
 0.95
 1.11
 0.57
 0.17
Diluted income from continuing operations per limited partner unit0.84
 0.93
 1.11
 0.57
 0.17
Basic income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Diluted income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Cash distribution per common unit1.17
 1.14
 1.08
 0.80
 0.67
Balance Sheet Data (at period end):         
Assets held for sale3,313
 3,588
 3,681
 3,372
 —
Total assets(1)
86,246
 78,925
 71,144
 64,266
 50,367
Liabilities associated with assets held for sale75
 48
 42
 47
 —
Long-term debt, less current maturities43,671
 42,608
 36,837
 29,477
 22,562
Total equity29,980
 22,431
 23,553
 22,301
 16,341
*As adjusted for the change in accounting policy related to inventory valuation, as discussed above.
(1)
Includes assets held for sale
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
Energy Transfer Equity, L.P.LP is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.“ET.” 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 for the years ended December 31, 2022 and 2021 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.
Discussion and analysis of matters pertaining to the year ended December 31, 2020 and year-to-year comparisons between the years ended December 31, 2021 and 2020 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2021 that was filed with the SEC on February 18, 2022.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE”“Energy Transfer” mean Energy Transfer Equity, L.P.LP and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. Referencessubsidiaries.
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Table of Contents
Index to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.Financial Statements
OVERVIEW
Energy Transfer Equity, L.P. directlyThe primary activities in which we are engaged, which are in the United States, and indirectly owns equity interests in ETPthe operating subsidiaries through which we conduct those activities are as follows:
•natural gas operations, including the following:
•natural gas midstream and Sunoco LP, both publicly traded master limited partnerships engaged in diversified energy-related services.intrastate transportation and storage;
The historical common units for ETP presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, discussed in “Item 1. Business.”•interstate natural gas transportation and storage; and
At January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP•crude oil, NGL and Sunoco LP consisted of 100% of the respective general partner interestsrefined products transportation, terminalling services and IDRs,acquisition and marketing activities, as well as approximately 27.5 million ETP common units,NGL storage and approximately 2.3 millionfractionation services.
In addition, we own investments in other businesses, including Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP,USAC, both of which are publicly traded master limited partnerships engagedpartnerships.
Energy Transfer derives cash flows from distributions related to its investment in diversified energy-related services,its subsidiaries, including Sunoco LP and USAC. The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the Partnership’s ownershipamount of Lake Charles LNG. The Parent Company’savailable cash. Energy Transfer’s primary cash requirements are for distributions to its partners, general and administrative expenses and 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 notrequirements. Energy Transfer distributes its available to satisfy the debts and other obligations of subsidiaries.
In order to fully understand the financial condition and results of operationscash remaining after satisfaction of the Parent Companyaforementioned cash requirements to its Unitholders on a stand-alone basis,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, Energy Transfer may issue debt or equity securities from time to time as we have included discussions of Parent Company matters apart from thosedeem prudent to provide liquidity for new capital projects of our consolidated group.subsidiaries or for other partnership purposes.
General
Our primary objective is to increase the level of our distributable cash flow to our unitholdersUnitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.
Our reportable segments are as follows:
Investment in ETP, including the consolidated operations of ETP;•intrastate transportation and storage;
Investment•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP, includingLP;
•investment in USAC; and
•all other.
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Recent Developments
Woodford Express Acquisition
On September 13, 2022, Energy Transfer completed the consolidated operationsacquisition of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities100% of the Parent Company;membership interests in Woodford Express, LLC, which owns a mid-continent gas gathering and processing system, for approximately $485 million plus working capital. The system, which is located in the heart of the SCOOP play, has 450 MMcf/d of cryogenic gas processing and treating capacity and over 200 miles of gathering lines, which are connected to Energy Transfer’s pipeline network. Woodford Express, LLC repaid aggregate principal of $292 million on its revolving credit facility and term loan on the closing date of the acquisition, which amount is included in the total consideration.
Energy Transfer Canada Sale
In August 2022, the goodwillPartnership completed the sale of its 51% interest in Energy Transfer Canada. The sale resulted in cash proceeds to Energy Transfer of $302 million.
Spindletop Assets Purchase
In March 2022, the Partnership purchased the membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for approximately $325 million.
Sunoco LP’s Acquisitions
On November 30, 2022, Sunoco LP completed the acquisition of Peerless Oil & Chemicals, Inc., an established terminal operator that distributes fuel products to over 100 locations within Puerto Rico and property, plantthroughout the Caribbean, for $76 million, net of cash acquired.
On April 1, 2022, Sunoco LP completed the acquisition of a transmix processing and equipment fair value adjustments recordedterminal facility in Huntington, Indiana for $252 million, net of cash acquired.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding an individual entity’s ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of the FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.
Even without application of the FERC’s recent rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost of service rates. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were
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agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding. On December 16, 2022, the FERC issued its order on Panhandle’s rate case. On January 17, 2023, Panhandle filed its request for rehearing in the proceeding.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the Natural Gas Act. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC will not apply the now draft 2022 Policy Statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments were due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2004 reverse acquisition2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Interstate Common Carrier Regulation
The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of Heritage Propane Partners, L.P.market-based rates. The FERC’s indexing methodology is subject to review every five years.
EachOn December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the respective general partnersJanuary 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit.
On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases. Specifically, the policy statement adopted the proposal in the FERC’s earlier Notice of ETPInquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen applied to complaints against index rate
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increases and Sunoco LP have separate operating managementinstead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for both protests and boardscomplaints against index rate increases. At this time, we cannot determine the effect of directors.a change in the FERC’s preliminary screen for complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash flows.
Trends and Outlook
Overall, we believe the Partnership’s outlook is strong, as it has a stable business that has demonstrated its ability to manage through various market cycles. We control ETPexpect future growth to be supported by production improvements, improved market conditions, and Sunoco LP throughincreased utilization of our ownershipexisting assets, as well as strong domestic and international demand for our products.
While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will continue to impact our business, we cannot predict the ultimate magnitude of their respective general partners.
Recent Developments
ETE Senior Notes Offeringthat impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors.
In October 2017, ETE issued $1 billion aggregate principal amountaddition, the U.S. economy has experienced rising inflation in 2022, which has resulted in higher costs for labor, services, and materials. Our suppliers and customers also face inflationary pressures, and our throughput volumes may be impacted if producers are constrained. While the rate and scope of 4.25% senior notes duevarious inflationary factors may increase our operating costs and capital expenditures materially, we anticipate that any such impacts would be recoverable in the prices of our services.
Ultimately, the extent to which our business will be impacted by future market developments depends on factors beyond our control, which are highly uncertain and cannot be predicted. In response to the recent market volatility and uncertainties, we have reduced growth capital spending in recent years, and we expect to continue to maintain a prudent level of growth capital spending going forward. See “Liquidity and Capital Resources” for additional information on our capital expenditures over the last two years and our forecasted capital expenditures for 2023. The $990 million net proceeds from
We currently have ample liquidity to fund our business, and we do not anticipate any liquidity concerns in the offering were usedimmediate future (see “Liquidity and Capital Resources”). In addition, we continue to repay a portionhave access to the debt capital markets on generally favorable terms. In the event we seek additional equity or debt capital, our blended cost of capital for equity and debt is expected to be modestly higher in the outstanding indebtedness under ETE’s term loan facilitynear term; however, we will continue to evaluate growth projects and for general partnership purposes.
Sunoco LP Series A Preferred Units
On March 30, 2017,acquisitions as such opportunities may be identified in the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interestsfuture in Sunoco LP in a private placement transaction for an aggregate purchase pricelight of $300 million. The distribution ratethis higher cost of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference. capital.
In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units.
January 2018 Sunoco LP Common Units Repurchase
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.

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

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

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

Year Ended December 31, 20172022 Compared to the Year Ended December 31, 20162021
Consolidated Results
Years Ended December 31,
20222021Change
Segment Adjusted EBITDA:
Intrastate transportation and storage$1,396 $3,483 $(2,087)
Interstate transportation and storage1,753 1,515 238 
Midstream3,210 1,868 1,342 
NGL and refined products transportation and services3,025 2,828 197 
Crude oil transportation and services2,187 2,023 164 
Investment in Sunoco LP919 754 165 
Investment in USAC426 398 28 
All other177 177 — 
Adjusted EBITDA (consolidated)$13,093 $13,046 $47 
 Years Ended December 31,  
 2017 2016* Change
Segment Adjusted EBITDA:     
Investment in ETP$6,712
 $5,733
 $979
Investment in Sunoco LP732
 665
 67
Investment in Lake Charles LNG175
 179
 (4)
Corporate and other(31) (170) 139
Adjustments and eliminations(268) (272) 4
Total7,320
 6,135
 1,185
Depreciation, depletion and amortization(2,554) (2,216) (338)
Interest expense, net of interest capitalized(1,922) (1,804) (118)
Gains on acquisitions—
 83
 (83)
Impairment losses(1,039) (1,040) 1
Losses on interest rate derivatives(37) (12) (25)
Non-cash unit-based compensation expense(99) (70) (29)
Unrealized gains (losses) on commodity risk management activities59
 (136) 195
Inventory valuation adjustments24
 97
 (73)
Losses on extinguishments of debt(89) —
 (89)
Impairment of investments in unconsolidated affiliates(313) (308) (5)
Equity in earnings of unconsolidated affiliates144
 270
 (126)
Adjusted EBITDA related to unconsolidated affiliates(716) (675) (41)
Adjusted EBITDA related to discontinued operations(223) (199) (24)
Other, net155
 79
 76
Income from continuing operations before income tax benefit710
 204
 506
Income tax benefit from continuing operations(1,833) (258) (1,575)
Income from continuing operations2,543
 462
 2,081
Income (loss) from discontinued operations, net of income taxes(177) (462) 285
Net income$2,366
 $—
 $2,366
Years Ended December 31,
20222021Change
Reconciliation of net income to Adjusted EBITDA:
Net income$5,868 $6,687 $(819)
Depreciation, depletion and amortization4,164 3,817 347 
Interest expense, net of interest capitalized2,306 2,267 39 
Income tax expense204 184 20 
Impairment losses and other386 21 365 
Gains on interest rate derivatives(293)(61)(232)
Non-cash compensation expense115 111 4 
Unrealized gains on commodity risk management activities(42)(162)120 
Inventory valuation adjustments (Sunoco LP)(5)(190)185 
Losses on extinguishments of debt— 38 (38)
Adjusted EBITDA related to unconsolidated affiliates565 523 42 
Equity in earnings of unconsolidated affiliates(257)(246)(11)
Other, net82 57 25 
Adjusted EBITDA (consolidated)$13,093 $13,046 $47 
* As adjusted.Net Income. For the year ended December 31, 2022 compared to the prior year, net income decreased $819 million, or approximately 12%, primarily due to increases in non-cash expenses, the most significant of which were a $347 million increase in depreciation, depletion and amortization and a $365 million increase in impairment losses and other. The changes in these non-cash items are discussed further below. The change in net income also reflects changes in Adjusted EBITDA, which are also discussed below.
SeeAdjusted EBITDA (consolidated). For the detailed discussionyear ended December 31, 2022 compared to the prior year, Adjusted EBITDA increased $47 million primarily due to favorable results in multiple segments, the most significant of which were in our midstream segment, where Segment Adjusted EBITDA increased by $1.34 billion primarily due to favorable natural gas and NGL prices, increased production and the impacts of recent acquisitions. These increases were substantially offset by the impacts of Winter Storm Uri in February 2021, with the Segmentmost significant impact in our intrastate transportation and storage segment.
Additional information on changes impacting Adjusted EBITDA for the year ended December 31, 2022 compared to the prior year, including other impacts from Winter Storm Uri and other non-storm-related factors, is available in “Segment Operating Results section below.Results.”
Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense increased primarily due to additional depreciation and amortization from assets recently placed in service.service and recent acquisitions.
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Interest Expense, Net of Interest Capitalized.Interest expense, net of interest capitalized, increased primarily due to the following:
•interest expense recognized by the Partnership (excluding Sunoco LP and USAC) increased by $12 million primarily due to higher weighted-average interest rates on long-term debt;
•an increase of $48$19 million of expense recognized by Sunoco LP primarily due to increased term loan borrowingsan increase in average total long-term debt and an increase in the issuance of senior notes;weighted-average interest rate on long-term debt; and
•an increase of $48$8 million of expense recognized by ETPUSAC primarily due to recenthigher weighted-average interest rates and increased borrowings under its credit facility, partially offset by a decrease in amortization of debt issuances by ETPissuance costs attributable to the amendment and restatement of its consolidated subsidiaries; andcredit facility agreement in the prior comparable period.
an increase of $20 million ofIncome Tax Expense. For the year ended December 31, 2022 compared to the same period last year, income tax expense recognized by the Parent Company primarilyincreased due to increased borrowings.recognition of a favorable valuation allowance adjustment for state net operating losses in a prior period.
GainsImpairment Losses and Other. For the year ended December 31, 2022, impairment losses and other included an $85 million loss on acquisitions. the deconsolidation of Energy Transfer Canada, which was recorded upon the completion of the sale in August 2022. The Partnership recorded gains of $83amount also included a $300 million in connection with recent acquisitions during 2016, including $41 millionimpairment related to Sunoco Logistics’ acquisitionEnergy Transfer Canada’s assets recorded in March 2022 based on the anticipated proceeds from the expected sale of those assets. The remainder of the remaining interest in SunVit.

Impairment Losses. In 2017, ETP recorded goodwill impairmentsimpairment losses were from USAC’s recognition of $262 millionimpairment losses related to its interstate transportation and storage operations, $79compression equipment.
For the year ended December 31, 2021, impairment losses included fixed asset impairments of $5 million recognized by USAC related to its NGLcompression equipment and refined products operations and $452$10 million recognized by Energy Transfer Canada related to its other operations. In 2016, ETP recorded goodwill impairments of $638 million related to its interstate transportation and storage operations and $32 million related to its midstream operations. These goodwill impairments were primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.
In 2017, Sunoco LP recognized goodwill impairment of $387 million, of which $102 million was allocated to continuing operations. In 2016, Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations. These goodwill impairments were due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
In addition, impairment losses also include $127 million and $133 million impairments to property,a processing plant, and equipment in ETP’s interstate transportation and storage operations in 2017 and 2016, respectively, due to decreases in projected future cash flows as well as a $10$6 million impairment of intangible assets related to property, plant and equipment in ETP’s midstream operations in 2016.customer contracts within the Partnership’s crude operations.
LossesGains on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. LossesGains on interest rate derivatives during the year ended December 31, 2017 and 2016 resulted from decreaseschanges in forward interest rates, which caused our market value of our forward-starting swaps to decreaseincrease in value.value, the effect of which was partially offset by a realized loss on the cash settlement of a portion of our these swaps.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See discussion of theThe unrealized gains (losses)and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the discussion ofunrealized gains and losses within each segment results below.are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 14 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Inventory Valuation Adjustments.Inventory valuation reserve adjustments were recorded forrepresent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory associated with Sunoco LP and ETP’s NGL and refined products and transportation services operations as a resultat the end of commodity price changes between periods.
Impairment of Investments in Unconsolidated Affiliates.the period. During the yearyears ended December 31, 2017, ETP recorded impairments to its investments2022 and 2021, increases in FEPfuel prices reduced lower of $141cost or market reserve requirements by $5 million and HPC$190 million, respectively, resulting in favorable impacts to net income.
Losses on Extinguishments of $172 million. DuringDebt. For the year endedDecember 31, 2016, ETP recorded an impairment2021, the losses on extinguishments of debt was related to Sunoco LP’s repurchase of its investment2026 senior notes in MEP2021, as well as the Partnership’s partial repayment of $308 million. Additional discussion on these impairments is includedits Term Loan in “EstimatesApril 2021 and Critical Accounting Policies” below.repurchase of $900 million of 5.875% senior notes.
Adjusted EBITDA Related to Unconsolidated AffiliatesandEquity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.
Other, net. Other, net in 2017 and 2016 primarily includes amortization of regulatory assets and other income and expense amounts.
Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35%
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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Years Ended December 31,
20222021Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus$141 $157 $(16)
MEP10 (17)27 
White Cliffs (1)
(8)— (8)
Explorer25 24 1 
Other89 82 7 
Total equity in earnings of unconsolidated affiliates$257 $246 $11 
Adjusted EBITDA related to unconsolidated affiliates(2):
Citrus$326 $327 $(1)
MEP45 18 27 
White Cliffs20 19 1 
Explorer41 39 2 
Other133 120 13 
Total Adjusted EBITDA related to unconsolidated affiliates$565 $523 $42 
Distributions received from unconsolidated affiliates:
Citrus$133 $235 $(102)
MEP27 12 15 
White Cliffs19 29 (10)
Explorer27 26 1 
Other88 77 11 
Total distributions received from unconsolidated affiliates$294 $379 $(85)
(1)For the year ended December 2016,31, 2022, equity in earnings (losses) of unconsolidated affiliates includes the Partnershipimpact of non-cash impairments recorded an income tax benefit due to pre-taxby White Cliffs, which reduced the Partnership’s equity in earnings by $9 million.
(2)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses at its corporate subsidiaries.

of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The following tables identify the components of Segment Adjusted EBITDA, which is calculated as follows:
•Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
•Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
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•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses related to equity awards. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
•Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Marginmargin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Marginmargin is similar to the GAAP measure of gross margin, except that Segment Marginsegment margin excludes charges for depreciation, depletion and amortization.
Following Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Margin to operating income, as reportedAdjusted EBITDA is included in the Partnership’s consolidated statementsfollowing tables for each segment where segment margin is presented.
In addition, for certain segments, the following sections include information on the components of operations:
 Years Ended December 31,
 2017 2016
Investment in ETP$8,253
 $6,747
Investment in Sunoco LP1,108
 1,156
Investment in Lake Charles LNG197
 197
Adjustments and eliminations(1) (1)
Total segment margin9,557
 8,099
    
Less:   
Operating expenses2,644
 2,307
Depreciation, depletion and amortization2,554
 2,216
Selling, general and administrative607
 693
Impairment losses1,039
 1,040
Operating income$2,713
 $1,843
Investmentsegment margin by sales type, which components are included in ETP
 Years Ended December 31,  
 2017
2016 Change
Revenues$29,054
 $21,827
 $7,227
Cost of products sold20,801
 15,080
 5,721
Segment margin8,253
 6,747
 1,506
Unrealized (gains) losses on commodity risk management activities(56) 131
 (187)
Operating expenses, excluding non-cash compensation expense(2,103) (1,841) (262)
Selling, general and administrative expenses, excluding non-cash compensation expense(392) (351) (41)
Adjusted EBITDA related to unconsolidated affiliates984
 946
 38
Other, net26
 101
 (75)
Segment Adjusted EBITDA$6,712
 $5,733
 $979
order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
Winter Storm Impacts
Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s Adjusted EBITDA and also affected the results of operations in certain segments. The recognition of the impacts of Winter Storm Uri during 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.
For additional information regarding our business segments, see “Item 1. Business” and Notes 1 and 16 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”
Segment Operating Results
Intrastate Transportation and Storage
Years Ended December 31,
20222021Change
Natural gas transported (BBtu/d)14,497 11,918 2,579 
Withdrawals from storage natural gas inventory (BBtu)27,283 32,038 (4,755)
Revenues$7,818 $8,571 $(753)
Cost of products sold6,000 4,769 1,231 
Segment margin1,818 3,802 (1,984)
Unrealized gains on commodity risk management activities(67)(46)(21)
Operating expenses, excluding non-cash compensation expense(334)(268)(66)
Selling, general and administrative expenses, excluding non-cash compensation expense(53)(36)(17)
Adjusted EBITDA related to unconsolidated affiliates26 27 (1)
Other6 4 2 
Segment Adjusted EBITDA$1,396 $3,483 $(2,087)
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Volumes. For the year ended December 31, 20172022 compared to the prior year, transported volumes increased primarily due to the acquisition of the Enable Oklahoma Intrastate Transmission system, as well as increased production in the Permian Basin and Haynesville Shale.
Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
Years Ended December 31,
20222021Change
Transportation fees$828 $740 $88 
Natural gas sales and other (excluding unrealized gains and losses)639 1,267 (628)
Retained fuel revenues (excluding unrealized gains and losses)186 180 6 
Storage margin, including fees (excluding unrealized gains and losses)98 1,569 (1,471)
Unrealized gains on commodity risk management activities67 46 21 
Total segment margin$1,818 $3,802 $(1,984)
Segment Adjusted EBITDA. For the year ended December 31, 2022 compared to the prior year, Segment Adjusted EBITDA related to the Investment in ETP increased primarily as a result of the following:
an increase of $13 million in ETP’sour intrastate transportation and storage operations resulting from an increase of $74 millionsegment decreased due to higherthe net impacts of the following:
•a decrease of $1.47 billion in realized gains from pipeline optimization activity and an increase of $10 million in retained fuel sales. These increases were offset by a $57 million decrease in transportation fees due to renegotiated contracts and an $11 million decrease in storage margin;
an increase of $348 million in ETP’s midstream operations primarily due to a $210 million increase in non-fee based margins (excluding changes in unrealized gains and losses) due to higher realized crude oil and NGL prices and volume increases and a $144 million increase in fee-based revenues due to minimum volume commitments in South Texas, increased volumes in

the Permian and Northeast regions, and recent acquisitions, including PennTex; these increases in gross margin were partially offset by increases in operating expenses of $17 million due to recent acquisitions, including PennTex.
an increase of $145 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $124 million, primarily due to higher volumes on Texas NGL pipelinesphysical storage margin from withdrawals during Winter Storm Uri in the prior period;
•a decrease of $628 million in realized natural gas sales and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $84 million,other primarily due to higher NGL volumes from most major producing regions; and an increasenatural gas sales at prevailing market prices during Winter Storm Uri in terminal services margin of $29 million due to a $43 million increase from higher throughput volumes on the Marcus Hook and Nederland NGL terminals offset by lower refined products terminal throughput and the sale of one of ETP’s refined product terminals in April 2017; partially offset by a decrease of $54 million in marketing margin (excluding changes in unrealized gains of $95 million) primarily due to the timing of the recognition of margin from optimization activities; prior period;
•an increase of $37$66 million in operating expenses primarily due to increased utilities costs associated with ETP’s fourth fractionator at Mont Belvieu anda $31 million increase from expenses related to the Mariner project ramp up at the Marcus Hook Industrial Complex and anaddition of Enable, a $19 million increase in generalcost of fuel consumption from higher gas prices, a $10 million increase in ad valorem tax expense and administrative expenses of $8a $7 million due to higher allocations;increase in utilities expense; and
•an increase of $545 million in ETP’s crude oil transportation and services operations due to an increase of $724 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $90 million from existing assets due to increased volumes throughout the system; and an increase of $16 million from increased throughput fees, and tank rentals, primarily from increased activity at ETP’s Nederland, Texas crude terminal; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; partially offset by a decrease of $78 million in margin from ETP’s crude oil acquisition and marketing business resulting from less favorable market price spreads particularly in the first three quarters of 2017; an increase of $183 million in operating expenses primarily due to placing the Bakken Pipeline in service; and an increase of $24$17 million in selling, general and administrative expenses primarily due to merger feesthe addition of Enable and higher legal and environmental reserves;expenses; partially offset by
a decrease•an increase of $19$88 million in ETP’stransportation fees primarily due to fees on the recently acquired Enable Oklahoma Intrastate Transmission system, partially offset by fees related to Winter Storm Uri in the prior period; and
•an increase of $6 million in retained fuel revenues related to natural gas prices.
Interstate Transportation and Storage
Years Ended December 31,
20222021Change
Natural gas transported (BBtu/d)14,727 10,310 4,417 
Natural gas sold (BBtu/d)29 23 6 
Revenues$2,251 $1,841 $410 
Cost of products sold25 11 14 
Segment margin2,226 1,830 396 
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses(791)(580)(211)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(131)(83)(48)
Adjusted EBITDA related to unconsolidated affiliates408 347 61 
Other41 1 40 
Segment Adjusted EBITDA$1,753 $1,515 $238 
Volumes. For the year ended December 31, 2022 compared to the prior year, transported volumes increased primarily due to the impact of the Enable Acquisition, higher utilization on our Tiger system due to increased production in the Haynesville Shale and higher volumes on our Panhandle and Trunkline systems due to increased demand.
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Segment Adjusted EBITDA. For the year ended December 31, 2022 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage operationssegment increased due to the net impacts of the following:
•an increase of $396 million in segment margin primarily due to a decrease$433 million increase from recently acquired assets, a $93 million increase in reservation revenuestransportation revenue from several of $45 million on the Panhandle, Trunkline, and Transwestern pipelines, a decrease of $17 million in gas parking service related revenues on the Panhandle and Trunkline pipelines primarilyour interstate pipeline systems due to lack of customer demand resulting from weak spreads, a decrease of $19 million in revenues on the Tiger pipeline due to contract restructuring,higher contracted volumes and higher rates, and a decrease of $5$13 million on the Sea Robin pipeline due to producer maintenance and production declines.increase in parking revenue. These decreasesincreases were partially offset by $55a $63 million of incremental revenuesdecrease from operational gas sales recorded in the placement in partial service of the Rover pipeline effective August 31, 2017,prior period, a $6$34 million dollar decrease in operating expensesreservation fees resulting from shipper contract expirations and $4a shipper bankruptcy during the prior period, a $32 million increasedecrease due to lower rates on our Panhandle system resulting from developments in adjusted EBITDA from unconsolidated affiliates;an ongoing rate case and
a decrease of $53$15 million in ETP’s all other operationsdecrease due to a decrease of $90 million related to the termination of management fees paid by ETE that ended in 2016; a decrease of $31 million from the mark-to-market of physical system gas and settled derivative; and shipper bankruptcy on our Rover system;
•an increase of $17 million in transaction related expenses; partially offset by an increase of $33$61 million in Adjusted EBITDA related to ETP’s investment in PES;unconsolidated affiliates primarily due to a one-time fee of $15$34 million receivedincrease from recently acquired assets, a $26 million increase from our Midcontinent Express Pipeline joint venture affiliate; as a result of higher revenue due to capacity sold at higher rates, and a $1 million increase from our Fayetteville Express Pipeline joint venture due to lower expenses; and
•an increase of $40 million in other Adjusted EBITDA primarily due to the realization in the current period of certain amounts related to shipper bankruptcies that occurred in a prior period; partially offset by
•an increase of $211 million in operating expenses primarily due to a $182 million increase from recently acquired assets, a $17 million increase in employee and other direct expenses, and a $10 million increase in maintenance project costs; and
•an increase of $48 million in selling, general and administrative expenses primarily due to recently acquired assets.
Midstream
Years Ended December 31,
20222021Change
Gathered volumes (BBtu/d)18,582 13,230 5,352 
NGLs produced (MBbls/d)800 644 156 
Equity NGLs (MBbls/d)44 36 8 
Revenues$17,101 $11,316 $5,785 
Cost of products sold12,682 8,569 4,113 
Segment margin4,419 2,747 1,672 
Unrealized gains on commodity risk management activities— (10)10 
Operating expenses, excluding non-cash compensation expense(1,087)(778)(309)
Selling, general and administrative expenses, excluding non-cash compensation expense(186)(126)(60)
Adjusted EBITDA related to unconsolidated affiliates25 32 (7)
Other39 3 36 
Segment Adjusted EBITDA$3,210 $1,868 $1,342 
Volumes. For the year ended December 31, 2022 compared to the prior year, gathered volumes and NGL production increased due to increases in all regions.
Segment Margin. The following table presents the components of our midstream segment margin.
Years Ended December 31, 
20222021Change
Gathering and processing fee-based revenues$3,035 $2,137 $898 
Non-fee-based contracts and processing1,384 600 784 
Unrealized gains on commodity risk management activities— 10 (10)
Total segment margin$4,419 $2,747 $1,672 
107
Segment Adjusted EBITDA. For the year ended December 31, 2022 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:
•an increase of $177 million in non-fee-based margin due to favorable natural gas prices of $64 million and NGL prices of $113 million;
•an increase of $464 million in non-fee-based margin due to recent acquisitions, as well as increased production in the South Texas, Northeast and Permian regions;
•an increase of $143 million in non-fee-based margin due to the impacts of Winter Storm Uri in the prior period;
•an increase of $898 million in fee-based margin due to recent acquisitions, as well as increased throughput in the South Texas, Northeast and Permian regions; and
•an increase of $36 million in other primarily due to the realization in the current period of certain amounts related to a shipper bankruptcy that occurred in a prior period; partially offset by
•an increase of $309 million in operating expenses primarily due to $210 million in incremental operating expenses from recent acquisitions, a $52 million increase from pricing increases in labor, materials and utilities, a $16 million increase in project-related costs and environmental remediation, and a $20 million increase in crudeemployee costs and power trading activates,allocated expenses;
•an increase of $60 million in selling, general and administrative expenses primarily due to a $35 million increase from the liquidationimpact of crude inventories;recent acquisitions, an $18 million increase in insurance costs and a $7 million increase in legal fees; and
•a decrease of $11$7 million in expenses related to ETP’s compression business.
Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates fordue to the yearssale of the Partnership’s membership interest in Ranch Westex JV LLC in 2022.
NGL and Refined Products Transportation and Services
Years Ended December 31,
20222021Change
NGL transportation volumes (MBbls/d)1,882 1,732 150 
Refined products transportation volumes (MBbls/d)521 496 25 
NGL and refined products terminal volumes (MBbls/d)1,274 1,174 100 
NGL fractionation volumes (MBbls/d)911 835 76 
Revenues$25,657 $19,961 $5,696 
Cost of products sold21,656 16,248 5,408 
Segment margin4,001 3,713 288 
Unrealized (gains) losses on commodity risk management activities16 (88)104 
Operating expenses, excluding non-cash compensation expense(962)(784)(178)
Selling, general and administrative expenses, excluding non-cash compensation expense(127)(112)(15)
Adjusted EBITDA related to unconsolidated affiliates97 97 — 
Other— 2 (2)
Segment Adjusted EBITDA$3,025 $2,828 $197 
Volumes. For the year ended December 31, 20172022 compared to the prior year, NGL transportation volumes increased primarily due to higher volumes from the Permian and 2016 consistedEagle Ford regions and higher volumes on our export pipelines into our Nederland Terminal.
Refined products transportation volumes increased for the year ended December 31, 2022 compared to prior year due to due to recovery from COVID-19 related demand reduction in the prior period.
NGL and refined products terminal volumes increased for the year ended December 31, 2022 compared to the prior year primarily due to higher volumes on our export pipelines into our Nederland Terminal and refined product demand recovery.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2022 compared to the prior year primarily due to increased production to our system, primarily from the Permian and Eagle Ford regions.
108
Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
Years Ended December 31,
20222021Change
Fractionators and refinery services margin$850 $712 $138 
Transportation margin2,126 2,016 110 
Storage margin284 271 13 
Terminal Services margin699 642 57 
Marketing margin58 (16)74 
Unrealized gains (losses) on commodity risk management activities(16)88 (104)
Total segment margin$4,001 $3,713 $288 
Segment Adjusted EBITDA. For the year ended December 31, 2022 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
•an increase of $138 million in fractionators and refinery services margin primarily due to a $151 million increase from higher volumes and higher rates driven by contractual rate escalations tied to broader economic inflationary measures, increased utilization of our ethane optimization strategy in 2022 and a $17 million intrasegment charge which is fully offset in our transportation margin. These increases were partially offset by a $30 million decrease from a less favorable pricing environment impacting our refinery services business;
•an increase of $110 million in transportation margin primarily due to a $193 million increase resulting from higher y-grade throughput and higher rates driven by contractual rate escalations tied to broader economic inflationary measures on our Texas pipeline system, a $12 million increase from higher exported volumes feeding into our Nederland Terminal, a $9 million increase from the timing of third-party deficiency payments on our northeast pipelines and a $4 million increase resulting from higher throughput on our Mariner East pipeline. These increases were partially offset by intrasegment charges of $68 million and $17 million which are fully offset within our marketing and fractionators margins, respectively, and a $24 million decrease resulting from lower throughput on our Mariner West pipeline due to customer maintenance in 2022;
•an increase of $74 million in marketing margin primarily due to a reduction in intrasegment charges of $68 million which are fully offset within our transportation margin, as well as higher gains of $6 million from the optimization of NGL and refined product inventories;
•an increase of $57 million in terminal services margin primarily due to a $41 million increase from higher export volumes loaded at our Nederland Terminal, a $13 million increase from higher throughput at our Marcus Hook Terminal and a $3 million increase from our refined products terminals; and
•an increase of $13 million in storage margin primarily due to fees generated from exported volumes; partially offset by
•an increase of $178 million in operating expenses due to a $121 million increase in gas and power utility costs, a $20 million increase in ad valorem taxes, a $10 million increase from maintenance project costs, an $8 million increase in employee costs, and increases totaling $19 million from various other operating expenses; and
•an increase of $15 million in selling, general and administrative expenses primarily due to a $10 million increase in overhead expenses allocated to the segment and a $4 million increase in direct employee related costs.
109
 Years Ended December 31,  
 2017 2016 Change
Citrus$336
 $329
 $7
FEP74
 75
 (1)
MEP88
 90
 (2)
HPC46
 61
 (15)
Sunoco LP268
 271
 (3)
Other172
 120
 52
Total Adjusted EBITDA related to unconsolidated affiliates$984
 $946
 $38
Crude Oil Transportation and Services

Years Ended December 31,
20222021Change
Crude transportation volumes (MBbls/d)4,345 3,886 459 
Crude terminals volumes (MBbls/d)2,964 2,567 397 
Revenue$25,982 $17,446 $8,536 
Cost of products sold22,917 14,759 8,158 
Segment margin3,065 2,687 378 
Unrealized gains on commodity risk management activities(14)(4)(10)
Operating expenses, excluding non-cash compensation expense(645)(547)(98)
Selling, general and administrative expenses, excluding non-cash compensation expense(224)(135)(89)
Adjusted EBITDA related to unconsolidated affiliates4 19 (15)
Other1 3 (2)
Segment Adjusted EBITDA$2,187 $2,023 $164 
These amounts represent ETP’s proportionate shareVolumes. For the year ended December 31, 2022 compared to the prior year, crude transportation volumes were higher primarily due to increases on our Texas pipeline systems, as well as the addition of Oklahoma and Bakken gathering assets through the Enable Acquisition. Volumes on our Bayou Bridge pipeline were higher primarily due to increased crude supply from Strategic Petroleum Reserve releases during 2022. Additionally, volumes benefited from assets placed into service, primarily Cushing South in April 2022 and the Ted Collins Link in June 2021. Volumes on our Bakken Pipeline were higher for the year ended December 31, 2022 primarily due to increased volumes from new and existing customers. Crude terminal volumes were higher due to Strategic Petroleum Reserve releases increasing throughput and export activity at our Gulf Coast terminals.
Segment Adjusted EBITDA. For the year ended December 31, 2022 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
•an increase of $368 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $173 million increase due to higher volumes on our Bakken Pipeline, an $80 million increase related to assets acquired in 2021, a $78 million increase in throughput at our Gulf Coast terminals due to Strategic Petroleum Reserve volumes, stronger refinery utilization and higher export demand, a $57 million increase from our Texas crude pipeline system due to higher volumes and a $17 million increase due to higher volumes on our Bayou Bridge pipeline, partially offset by a $7 million decrease on other crude pipelines from lower volumes, and a $30 million decrease from our crude oil acquisition and marketing business primarily due to less favorable pricing conditions impacting our trading operations and unfavorable inventory valuation adjustments from crude oil prices; partially offset by
•an increase of $98 million in operating expenses primarily due to $32 million in higher volume-driven expenses, $31 million in higher project expenses and $17 million from expenses related to assets acquired in 2021;
•an increase of $89 million in selling, general and administrative expenses primarily due to the net impact of the resolution of two legal matters; and
•a decrease of $15 million in Adjusted EBITDA of itsrelated to unconsolidated affiliates and are based on ETP’s equitydue to the consolidation of certain operations that were previously reflected in earnings or lossesunconsolidated affiliates.
110
Investment in Sunoco LP
Years Ended December 31,   Years Ended December 31, 
2017 2016 Change 20222021Change
Revenues$11,723
 $9,986
 $1,737
Revenues$25,729 $17,596 $8,133 
Cost of products sold10,615
 8,830
 1,785
Cost of products sold24,350 16,246 8,104 
Segment margin1,108
 1,156
 (48)Segment margin1,379 1,350 29 
Unrealized (gains) losses on commodity risk management activities(3) 5
 (8)Unrealized (gains) losses on commodity risk management activities21 (14)35 
Operating expenses, excluding non-cash compensation expense(456) (455) (1)Operating expenses, excluding non-cash compensation expense(396)(329)(67)
Selling, general and administrative, excluding non-cash compensation expense(116) (142) 26
Selling, general and administrative, excluding non-cash compensation expense(111)(93)(18)
Inventory fair value adjustments(24) (98) 74
Adjusted EBITDA from discontinued operations223
 199
 24
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates10 9 1 
Inventory valuation adjustmentsInventory valuation adjustments(5)(190)185 
Other, netOther, net21 21 — 
Segment Adjusted EBITDA$732
 $665
 $67
Segment Adjusted EBITDA$919 $754 $165 
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
Segment Adjusted EBITDA. For the year ended December 31, 20172022 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:
•an increase in profit on motor fuel sales of $178 million, primarily due to a 14.2% increase in profit per gallon sold and a 2.3% increase in gallons sold; and
•an increase in non-motor fuel profit of $70 million, primarily due to an increase in storage tanks and terminals profit in 2022. This increase was primarily a result of the 2021 fourth quarter acquisition of refined product terminals. In addition, increased credit card transactions and merchandise gross profit contributed $15 million to the overall increase; partially offset by
•an increase in operating costs of $85 million, primarily due to higher costs as a result of the following:
an increase of $18 million in gross margin (excluding a $74 million change in fair value adjustments related to inventoryrecent acquisitions, higher employee costs, credit card processing fees, advertising costs, legal costs, insurance costs and unrealized gains and losses on commodity risk management activities) primarily caused by an increase in wholesale motor fuel gross profit per gallon, partially offset by a net increase in other gross profit consisting of merchandise, rental & other and retail motor fuel of $13 million;
a decrease of $26 million in general and administrative expenses primarily due to higher costs in 2016 related to relocation, employee termination, and higher contract labor and professional fees as the Partnership transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas to Dallas during 2016; and
an increase of $24 million related to discontinued operations; offset by
an increase of $1 million in other operating expenses primarily attributable to Sunoco LP’s retail business which has expanded through third-party acquisitions as well as through the construction of new-to-industry sites.

maintenance costs.
Investment in Lake Charles LNGUSAC
 Years Ended December 31, 
 20222021Change
Revenues$705 $633 $72 
Cost of products sold111 85 26 
Segment margin594 548 46 
Operating expenses, excluding non-cash compensation expense(123)(109)(14)
Selling, general and administrative, excluding non-cash compensation expense(45)(41)(4)
Segment Adjusted EBITDA$426 $398 $28 
 Years Ended December 31,  
 2017 2016 Change
Revenues$197
 $197
 $—
Operating expenses, excluding non-cash compensation expense(19) (16) (3)
Selling, general and administrative, excluding non-cash compensation expense(3) (2) (1)
Segment Adjusted EBITDA$175
 $179
 $(4)
Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Consolidated Results
 Years Ended December 31,  
 2016* 2015* Change
Segment Adjusted EBITDA:     
Investment in ETP$5,733
 $5,517
 $216
Investment in Sunoco LP665
 719
 (54)
Investment in Lake Charles LNG179
 196
 (17)
Corporate and other(170) (104) (66)
Adjustments and eliminations(272) (590) 318
Total6,135
 5,738
 397
Depreciation, depletion and amortization(2,216) (1,951) (265)
Interest expense, net of interest capitalized(1,804) (1,622) (182)
Gain on acquisitions83
 —
 83
Impairment losses(1,040) (339) (701)
Losses on interest rate derivatives(12) (18) 6
Non-cash compensation expense(70) (91) 21
Unrealized losses on commodity risk management activities(136) (65) (71)
Inventory valuation adjustments97
 (67) 164
Losses on extinguishments of debt—
 (43) 43
Impairment of investment in unconsolidated affiliate(308) —
 (308)
Equity in earnings of unconsolidated affiliates270
 276
 (6)
Adjusted EBITDA related to unconsolidated affiliates(675) (713) 38
Adjusted EBITDA related to discontinued operations(199) (228) 29
Other, net79
 23
 56
Income from continuing operations before income tax expense204
 900
 (696)
Income tax expense (benefit) from continuing operations(258) (123) (135)
Income from continuing operations462
 1,023
 (561)
Income (loss) from discontinued operations, net of income taxes(462) 38
 (500)
Net income$—
 $1,061
 $(1,061)
* As adjusted.
See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation and amortization from assets recently placed in service.

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

Segment Operating Results
Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 Years Ended December 31,
 2016 2015
Investment in ETP$6,747
 $7,578
Investment in Sunoco LP1,156
 980
Investment in Lake Charles LNG197
 216
Adjustments and eliminations(1) (1,346)
Total segment margin8,099
 7,428
    
Less:   
Operating expenses2,307
 2,303
Depreciation, depletion and amortization2,216
 1,951
Selling, general and administrative693
 548
Impairment losses1,040
 339
Operating income$1,843
 $2,287
Investment in ETP
 Years Ended December 31,  
 2016 2015 Change
Revenues$21,827
 $34,292
 $(12,465)
Cost of products sold15,080
 26,714
 (11,634)
Segment margin6,747
 7,578
 (831)
Unrealized losses on commodity risk management activities131
 65
 66
Operating expenses, excluding non-cash compensation expense(1,841) (2,621) 780
Selling, general and administrative expenses, excluding non-cash compensation expense(351) (482) 131
Inventory valuation adjustments—
 (58) 58
Adjusted EBITDA related to unconsolidated affiliates946
 937
 9
Other, net101
 98
 3
Segment Adjusted EBITDA$5,733
 $5,517
 $216
Segment Adjusted EBITDA. For the year ended December 31, 20162022 compared to last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:
•an increase of $46 million in segment margin primarily due to an increase in contract operations revenue which was primarily the result of Consumer Price Index-based and other price increases on customer contracts that occur as market conditions permit, and higher revenue generating horsepower; partially offset by
•an increase of $14 million in operating expenses primarily due to higher employee costs, an increase in retail parts and service expenses, an increase in vehicle fleet expenses primarily due to increased fuel costs and increased usage as well as higher costs of maintenance during the current period, and sales tax refunds received in the prior period.
111
All Other
Years Ended December 31,
20222021Change
Revenue$3,574 $3,476 $98 
Cost of products sold3,328 3,068 260 
Segment margin246 408 (162)
Unrealized losses on commodity risk management activities2 — 2 
Operating expenses, excluding non-cash compensation expense(80)(151)71 
Selling, general and administrative expenses, excluding non-cash compensation expense(60)(110)50 
Adjusted EBITDA related to unconsolidated affiliates4 1 3 
Other and eliminations65 29 36 
Segment Adjusted EBITDA$177 $177 $— 
Amounts reflected in our all other segment primarily include:
•our natural gas marketing operations;
•our wholly-owned natural gas compression operations;
•our investment in coal handling facilities; and
•our Canadian operations, until those assets were divested in August 2022.
Segment Adjusted EBITDA. For the year ended December 31, 2022 compared to the prior year, Segment Adjusted EBITDA related to the Investment in ETP increased primarily as a result of the following:
an increase of $70 million on ETP’s intrastate transportation and storage operations driven by $34 million in natural gas sales (excluding changes in unrealized losses of $17 million) primarily due to higher realized gains from the buying and selling of gas along ETP’s system and an increase of $37 million in storage margin (excluding net changes in unrealized amounts of $28 million related to fair value inventory adjustments and unrealized gains and losses on derivatives);
an increase of $317 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation and terminal margin of $239 millionwas unchanged primarily due to the ramp-upnet impacts of several organic growth projects as well as increased volumes from all producing regions; the following:
•an increase in fractionation and refinery services margin of $118$30 million (excluding unrealized gains and losses) primarily due to higher NGL volumes from most major producing regions; an increasemerger and acquisition expense in storage margin of $36 million primarily due to increased volumes from ETP’s Mont Belvieu fractionators; partially offset by a decrease in marketing margin of $42 million (excluding net changes in unrealized gains and losses of $50 million) primarily due to lower spreads, the timing of withdrawals, and the timing of the recognition of margin from optimization activities; partially offset by prior period;
•an increase of $33$7 million in operating expenses primarily due to increased costs associated withhigher franchise and sales taxes in the prior period;

organic growth projects such as our third fractionator in Mont Belvieu,Texas, Mariner East 1, Mariner South and Allegheny Access; and
•an increase of $313$25 million in ETP’s crude oil transportation and services operations due to a favorable environment for physical gas trading and storage activities;
•an increase of $158$14 million resulting primarily from placingdue to higher coal royalties at our Permian Express II pipeline in service in the third quarter of 2015, as well as the acquisition of a crude oil gathering system in West Texas; natural resources business;
•an increase of $49$13 million from existing assets due to increased volumes throughout the system; an increase of $31 million froma favorable environment for our crude terminals assets, largely related to the Nederland facility;power trading activities; and an increase of $74 million from our crude oil acquisition and marketing activity; offset by an increase of $5 million in selling, general and administrative expenses; partially offset by
a decrease $38 million in ETP’s interstate transportation and storage operations caused by a $56 million decrease in revenues primarily caused by contract restructuring on the Tiger pipeline, lower reservation revenues on the Panhandle and Trunkline pipelines, lower sales of capacity in the Phoenix and San Juan areas on the Transwestern pipeline, the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service, the expiration of a transportation rate schedule on the Transwestern pipeline, and declines in production and third-party maintenance on the Sea Robin pipeline, partially offset by higher reservation revenues on the Transwestern pipeline and higher parking revenues on the Panhandle and Trunkline pipelines;
•a decrease of $104$12 million in ETP’s midstream operations due to decreases in gathered volumes primarily due to declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partiallyad valorem taxes; offset by increases in the Permian region and the impact of recent acquisitions, including PennTex; and
•a decrease of $308$68 million due to gains in the prior period related to Winter Storm Uri; and
•a decrease of $35 million due to the transfer and contributionsale of ETP’s retail marketing assets to Sunoco LP. The consolidated results of Sunoco LP are reflected in the results for ETP’s all other above through June 2015. Effective July 1, 2015, Sunoco LP was deconsolidated, and the results for all other reflect adjusted EBITDA related to unconsolidated affiliates for ETP’s limited partner interests in Sunoco LP. The impact of the deconsolidation of Sunoco LP reduced segment margin, operating expenses and selling, general and administrative expenses; the impact to segment adjusted EBITDA is offset by the incremental adjusted EBITDA related to unconsolidated affiliates from ETP’s equity method investment in Sunoco LP subsequent to the deconsolidation; andEnergy Transfer Canada.
a decrease of $76 million in adjusted EBITDA related to ETP’s investment in PES.
Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2016 and 2015 consisted of the following:
 Years Ended December 31,  
 2016 2015 Change
Citrus$329
 $315
 $14
FEP75
 75
 —
MEP90
 96
 (6)
HPC61
 61
 —
Sunoco, LLC—
 91
 (91)
Sunoco LP271
 137
 134
Other120
 162
 (42)
Total Adjusted EBITDA related to unconsolidated affiliates$946
 $937
 $9
These amounts represent ETP’s proportionate share of the Adjusted EBITDA of its unconsolidated affiliates and are based on ETP’s equity in earnings or losses of its unconsolidated affiliates adjusted for its proportionate share of the unconsolidated affiliates’ interest, depreciation, amortization, non-cash items and taxes.

Investment in Sunoco LP
 Years Ended December 31,  
 2016 2015 Change
Revenues$9,986
 $12,430
 $(2,444)
Cost of products sold8,830
 11,450
 (2,620)
Segment margin1,156
 980
 176
Unrealized losses on commodity risk management activities5
 2
 3
Operating expenses, excluding non-cash compensation expense(455) (451) (4)
Selling, general and administrative, excluding non-cash compensation expense(142) (118) (24)
Inventory fair value adjustments(98) 78
 (176)
Adjusted EBITDA from discontinued operations199
 228
 (29)
Segment Adjusted EBITDA$665
 $719
 $(54)
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. Sunoco LP obtained control of MACS in October 2014, Sunoco, LLC in April 2015, Susser in July 2015, and Sunoco Retail LLC in March 2016. Because these entities were under common control, Sunoco LP recast its financial statements to retrospectively consolidate each of the entities beginning September 1, 2014. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
Segment Adjusted EBITDA. For the year ended December 31, 2016 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP decreased primarily as a result of the following:
a change of $176 million in the fair value adjustment to inventory resulting from changes in fuels prices during the year ended December 31, 2016;
a decrease of $29 million related to Sunoco LP’s retail operations that have been classified as discontinued operations;
an increase of $24 million in general and administrative expenses primarily due to $18 million for the transition of employees from Houston, Texas, Corpus Christi, Texas and Philadelphia, Pennsylvania to Dallas, Texas, with the remaining increase due to higher professional fees and other administrative expenses; partially offset by
an increase of $176 million in segment margin primarily caused by an increase in wholesale motor fuel gross profit of $212 million due to a 28.7%, or $0.55, decrease in the cost per wholesale motor fuel gallon, offset by a decrease in the gross profit on retail motor fuel of $37 million.
Investment in Lake Charles LNG
 Years Ended December 31,  
 2016 2015 Change
Revenues$197
 $216
 $(19)
Operating expenses, excluding non-cash compensation expense(16) (17) 1
Selling, general and administrative, excluding non-cash compensation expense(2) (3) 1
Segment Adjusted EBITDA$179
 $196
 $(17)
Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.

LIQUIDITY AND CAPITAL RESOURCES
Overview
Parent Company Only
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The amount of cash that ETP and Sunoco LP distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below. In connection with previous transactions, we have relinquished a portion of our incentive distributions to be received from ETP and Sunoco LP, see additional discussion under “Cash Distributions.”
The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with cash flows from its direct and indirect investments in ETP, Sunoco LP and Lake Charles LNG. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
The Parent Company expects ETP, Sunoco LP and Lake Charles LNG and their respective subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as it deems prudent to provide liquidity for new capital projects of its subsidiaries or for other partnership purposes.
ETP
ETP’sOur ability to satisfy itsour obligations and pay distributions to its Unitholders will depend on itsour future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control. The significant trends and uncertainties that we currently believe could significantly impact our liquidity and cash flows going forward are discussed in “Trends and Outlook” above.
We believe that we have sufficient liquidity and sources of funding to meet our cash requirements over the controlnear term and for the longer term. We expect to satisfy our working capital needs through cash generated by our operations. As of ETP’s management.December 31, 2022, we had cash and cash equivalents of $257 million and availability under our revolving credit facility of $4.18 billion.
ETPThe Partnership’s material contractual obligations include long-term debt service, payments under operating leases and purchase commitments. The Partnership’s obligations under its long-term debt agreements are described below under “Description of Indebtedness,” and information on the maturities and interest rates related to the Partnership’s long-term debt is available in Note 6 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.” In addition, information on the Partnership’s obligations under its lease arrangements is included in Note 13 to the consolidated financial statements in Item 8.
We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed,
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minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. We have material purchase commitments for crude oil; as of December 31, 2022, those purchase commitments totaled an estimated $39.65 billion (of which $16.17 billion would be due in 2023) based on either the current market price for variable price contracts or the contracted price for fixed price contracts.
We currently expectsexpect capital expenditures in 20182023 to be within the following ranges:ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):
GrowthMaintenance
LowHighLowHigh
Intrastate transportation and storage$25 $50 $50 $60 
Interstate transportation and storage275 300 175 185 
Midstream825 900 190 200 
NGL and refined products transportation and services (1)
325 375 120 130 
Crude oil transportation and services (1)
100 125 125 130 
All other (including eliminations)25 50 65 70 
Total capital expenditures$1,575 $1,800 $725 $775 
 Growth Maintenance
 Low High Low High
Intrastate transportation and storage$225
 $250
 $30
 $35
Interstate transportation and storage (1)
450
 500
 115
 120
Midstream750
 800
 120
 130
NGL and refined products transportation and services2,425
 2,475
 65
 75
Crude oil transportation and services (1)
425
 525
 90
 100
All other (including eliminations)75
 100
 60
 65
Total capital expenditures$4,350
 $4,650
 $480
 $525
            Less: Project level non-recourse financing—
 —
 —
 —
Partnership level capital funding$4,350
 $4,650
 $480
 $525
(1)Includes capital expenditures related to the Partnership’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline joint ventures, as well as the Orbit Gulf Coast NGL Exports joint venture.
(1)
Includes capital expenditures related to ETP’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.
The assets used in ETP’sour natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, ETP doeswe do not have any significant financial commitments for maintenance capital expenditures in itsour businesses. From time to time ETP experienceswe experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, ETP includeswe include these factors in itsour anticipated growth capital expenditures for each year.
ETPWe generally fundsfund maintenance capital expenditures and distributions with cash flows from operating activities. ETPWe generally expect to funds growth capital expenditures with proceeds of borrowings under our credit facilities, long-term debt, the issuance of additional Common Units or a combination thereof.
As of December 31, 2017, in addition to $306 million of cash on hand, ETP had available capacity under the ETP Credit Facilities of $2.51 billion. Based on ETP’s current estimates, it expects to utilize capacity under the ETP Credit Facilities, along with cash from operations.

from operations, to fund its announced growth capital expenditures and working capital needs through the end of 2018; however, ETP may issue debt or equity securities prior to that time as it deems prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.
Sunoco LP
Sunoco LP’s primary sources of liquidity consist of cash generated from operating activities, borrowings under its $1.50 billion credit facility and the issuance of additional long-term debt or partnership units as appropriate given market conditions. At December 31, 2017, Sunoco LP had available borrowing capacity of $726 million under its revolving credit facility and $28 million of cash and cash equivalents on hand.
In 2018, Sunoco LP expects to invest approximately $90at least $60 million in growth capital expenditures and approximately $40$150 million onin maintenance capital expenditures. Sunoco LP may revise the timing of these expenditures as necessaryin 2023.
USAC currently plans to adapt to economic conditions.spend approximately $26 million in maintenance capital expenditures and currently has budgeted between $260 million and $270 million in expansion capital expenditures in 2023.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price of our subsidiaries’ products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitionacquisitions of assets, while changes in non-cash unit-based compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when ETPEnergy Transfer has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk managementderivative assets and liabilities, timing of
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accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.
Following is a summary of operating activities by period:
Year Ended December 31, 20172022
Cash provided by operating activities in 20172022 was $4.43$9.05 billion and net income was $2.37$5.87 billion. The difference between net income and cash provided by operating activities in 20172022 primarily consisted of net non-cash items totaling $1.78$4.53 billion andoffset by net changes in operating assets and liabilities of $192 million.$1.50 billion. The non-cash activity in 20172022 consisted primarily of depreciation, depletion and amortization of $2.55$4.16 billion, impairment lossesof$1.35 billion, deferred income tax benefit of $1.87 billion,$386 million, non-cash compensation expense of $115 million, equity in earnings of unconsolidated affiliates of $257 million, inventory valuation adjustments of $24$5 million, losses on extinguishments and deferred income taxes of debt$187 million. The Partnership also received distributions of $89$232 million and non-cash compensation expense of$99 million.from unconsolidated affiliates.
Year Ended December 31, 20162021
Cash provided by operating activities in 20162021 was $3.32$11.16 billion and net income was $0 million.$6.69 billion. The difference between net income and cash provided by operating activities in 20162021 primarily consisted of net non-cash items totaling $2.77$3.80 billion andoffset by net changes in operating assets and liabilities of $179$515 million. The non-cash activity in 20162021 consisted primarily of depreciation, depletion and amortization of $2.22$3.82 billion, impairment losses of $1.35 billion, deferred income tax benefit$21 million, non-cash compensation expense of $177$111 million, equity in earnings of unconsolidated affiliates of $246 million, inventory valuation adjustments of $97 million and non-cash compensation expense of $70 million.
Year Ended December 31, 2015
Cash provided by operating activities in 2015 was $2.98 billion and net income was $1.06 billion. The difference between net income and cash provided by operating activities in 2015 primarily consisted of net non-cash items totaling $2.42 billion and changes in operating assets and liabilities of $0.87 billion. The non-cash activity in 2015 consisted primarily of depreciation, depletion and amortization of $1.95 billion, impairment losses of $339 million, deferred income tax expense of $239 million,

inventory valuation adjustments of $67$190 million, losses on extinguishmentsextinguishment of debt of $43$38 million, and non-cash compensation expensedeferred income taxes of $91$141 million.The Partnership also received distributions of $212 million from unconsolidated affiliates.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions to our joint ventures.of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund their respectiveour construction and expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 20172022
Cash used in investing activities in 2017 of $5.61 billion2022 was comprised primarily of$4.02 billion. Total capital expenditures of $8.41 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $5.47 billion for growth were $3.33 billion. Additional detail related to our capital expenditures and $429is provided in the following table. We received $78 million for maintenance capital expenditures during 2017. Weof cash proceeds from the sale of assets. The Partnership also received distributions of $62 million from unconsolidated affiliates. In 2022, we paid net$1.14 billion in cash for acquisitions, net of $303cash received. In 2022, we received $302 million includingin cash from the acquisitionsale of a noncontrolling interest.our interest in Energy Transfer Canada.
Year Ended December 31, 20162021
Cash used in investing activities in 2016 of $8.98 billion2021 was comprised primarily of$2.78 billion. Total capital expenditures of $7.70 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $5.44 billion for growth were $2.78 billion. Additional detail related to our capital expenditures and $368is provided in the following table. We received $45 million for maintenance capital expenditures during 2016. Weof cash proceeds from the sale of assets. The Partnership also received distributions of $167 million from unconsolidated affiliates. In 2021, we paid net$205 million in cash for acquisitions, net of $1.40 billion, includingcash received.
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The following is a summary of the acquisition of a noncontrolling interest.
Year Ended December 31, 2015
Cash used in investing activities in 2015 of $9.74 billion was comprised primarily ofPartnership’s capital expenditures (including only our proportionate share of $8.99 billion (excluding the allowance for equity funds used during constructionBakken, Rover, Bayou Bridge and Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs). ETP invested $7.68 billion for growth capital expenditures and $485 million for maintenance capital expenditures during 2015. We paid net cash for acquisitions of $842 million, including the acquisition of a noncontrolling interest. by period:
Capital Expenditures Recorded During Period
GrowthMaintenanceTotal
Year Ended December 31, 2022:
Intrastate transportation and storage$132 $47 $179 
Interstate transportation and storage456 188 644 
Midstream812 192 1,004 
NGL and refined products transportation and services376 131 507 
Crude oil transportation and services120 126 246 
Investment in Sunoco LP132 54 186 
Investment in USAC145 24 169 
All other (including eliminations)32 59 91 
Total capital expenditures$2,205 $821 $3,026 
Year Ended December 31, 2021:
Intrastate transportation and storage$17 $35 $52 
Interstate transportation and storage35 124 159 
Midstream365 119 484 
NGL and refined products transportation and services637 114 751 
Crude oil transportation and services250 93 343 
Investment in Sunoco LP135 39 174 
Investment in USAC40 20 60 
All other (including eliminations)98 37 135 
Total capital expenditures$1,577 $581 $2,158 
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions increaseto partners increased between the periods based onas a result of increases in the number of common units outstanding or increases in the distribution rate.
Following is a summary of financing activities by period:
Year Ended December 31, 20172022
Cash provided byused in financing activities was $953 million$5.11 billion in 2017. We2022. In 2022, we had a consolidated increasenet decrease in our debt level of $340$843 million. During 2022, we paid distributions of $3.05 billion to our partners, we paid distributions of $1.55 billion to noncontrolling interests, and we paid distributions of $49 million primarily due to theour redeemable noncontrolling interests. In addition, we received capital contributions of $405 million in cash from noncontrolling interests. During 2022, we incurred debt issuance costs of Parent Company and subsidiary senior notes, as well as increases$27 million.
Year Ended December 31, 2021
Cash used in financing activities was $8.42 billion in 2021. In 2021, we had a net decrease in our revolving credit facilities during 2015. Our subsidiaries alsodebt level of $6.05 billion. During 2021, we paid distributions of $1.90 billion to our partners, we paid distributions of $1.49 billion to noncontrolling interests, and we paid distributions of $49 million to our redeemable noncontrolling interests. In addition, we received $3.24 billioncapital contributions of $226 million in proceedscash from common unit offerings, including $2.28 billion from thenoncontrolling interests. During 2021, we incurred debt issuance costs of ETP Common Units and $952$14 million. During 2021, we received $889 million from the issuance of other subsidiary commonpreferred units. We paid distributions
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Year Ended December 31, 2016
Cash provided by financing activities was $5.93 billion in 2016. We had a consolidated increase in our debt level of $6.71 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $2.56 billion in proceeds from common unit offerings, including $1.10 billion from the issuance of ETP Common Units and $1.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $1.02 billion, and our subsidiaries paid $2.77 billion on limited partner interests other than those held by the Parent Company.
Year Ended December 31, 2015
Cash provided by financing activities was $6.79 billion in 2015. We had a consolidated increase in our debt level of $6.63 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $3.89 billion in proceeds from common unit offerings, including $1.43 billion from

the issuance of ETP Common Units and $2.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $1.09 billion, and our subsidiaries paid $2.34 billion on limited partner interests other than those held by the Parent Company. We also paid $1.06 billion to repurchase common units during the year ended December 31, 2015.
Discontinued Operations
Following is a summary of activities related to discontinued operations by period:
Year Ended December 31, 2017
Cash provided by discontinued operations was $93 million for the year ended December 31, 2017 resulting from cash provided by operating activities of $136 million, cash used in investing activities of $38 million and changes in cash included in current assets held for sale of $5 million.
Year Ended December 31, 2016
Cash used in discontinued operations was $385 million for the year ended December 31, 2016 resulting from cash provided by operating activities of $93 million, cash used in investing activities of $483 million and changes in cash included in current assets held for sale of $5 million.
Year Ended December 31, 2015
Cash used in discontinued operations was $283 million for the year ended December 31, 2015 resulting from cash provided by operating activities of $90 million, cash used in investing activities of $360 million and changes in cash included in current assets held for sale of $13 million.

Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
December 31,
20222021
Energy Transfer Indebtedness:
Notes and Debentures(1)(2)
$39,468 $37,733 
Five-Year Credit Facility793 2,937 
Subsidiary Indebtedness:
Transwestern Senior Notes250 400 
Panhandle Notes and Debentures(2)
— 235 
Bakken Senior Notes (3)
1,850 2,500 
Sunoco LP Senior Notes and lease-related obligations2,694 2,700 
USAC Senior Notes1,475 1,475 
HFOTCO Tax Exempt Notes225 225
Revolving Credit Facilities:
Sunoco LP Credit Facility900 581 
USAC Credit Facility646 516 
Energy Transfer Canada facilities(4)
— 398 
Other long-term debt3 3 
Net unamortized premiums, discounts and fair value adjustments183 238 
Deferred debt issuance costs(225)(239)
Total debt48,262 49,702 
Less: current maturities of long-term debt2 680 
Long-term debt, less current maturities$48,260 $49,022 
 December 31,
 2017 2016
Parent Company Indebtedness:   
ETE Senior Notes due October 2020$1,187
 $1,187
ETE Senior Notes due January 20241,150
 1,150
ETE Senior Notes due June 20271,000
 1,000
ETE Senior Notes due March 20231,000
 —
ETE Senior Secured Term Loan due December 2, 2019—
 2,190
ETE Senior Secured Term Loan due February 2, 20241,220
 —
ETE Senior Secured Revolving Credit Facility due December 18, 2018—
 875
ETE Senior Secured Revolving Credit Facility due March 24, 20221,188
 —
Subsidiary Indebtedness:   
ETP Senior Notes27,005
 24,855
Panhandle Senior Notes785
 1,085
Sunoco, Inc. Senior Notes—
 400
Transwestern Senior Notes575
 657
Sunoco LP Senior Notes, Term Loan and lease-related obligations3,556
 3,561
Credit Facilities and Commercial Paper:   
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (1)
50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019765
 1,000
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
PennTex $275 million MLP Revolving Credit Facility due December 2019—
 168
Other long-term debt8
 31
Unamortized premiums and fair value adjustments, net50
 101
Deferred debt issuance costs(247) (257)
Total debt44,084
 43,802
Less: current maturities of long-term debt413
 1,194
Long-term debt, less current maturities$43,671
 $42,608
(1)As of December 31, 2022, this balance included a total of $3.25 billion aggregate principal amount of senior notes due on or before December 31, 2023 which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
(1)
(2)In November 2022, Energy Transfer and Panhandle completed an internal reorganization which resulted in Energy Transfer assuming all of Panhandle’s $235 million outstanding principal amount of notes and debentures. The transaction did not impact the Partnership’s consolidated long-term debt.
(3)As of December 31, 2021, this balance included $650 million of 3.625% Senior Notes due April 2022 included in current maturities of long-term debt. These notes were repaid in April 2022.
(4)These facilities were included in the August 2022 Energy Transfer Canada divestiture as discussed in “Recent Developments” above.
Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The terms of our consolidated indebtedness and that of our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements.statements, included in “Item 8. Financial Statements and Supplementary Data.”
Senior Notes and Term Loan- Recent Transactions
Energy Transfer Equity, L.P.In February 2022, the Partnership redeemed $300 million aggregate principal amount of its 4.65% Senior Notes Offering due February 2022 with proceeds from its Five-Year Credit Facility.
In April 2022, Dakota Access redeemed $650 million aggregate principal amount of its 3.625% Senior Notes due April 2022 using proceeds from contributions made by its members. The Partnership indirectly owns 36.4% of the ownership interests in Dakota Access.
In August 2022, the Partnership exercised its par call option and fully redeemed $700 million aggregate principal amount of its 5.00% Senior Notes due October 2017, ETE2022 with proceeds from its Five-Year Credit Facility.
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In December 2022, the Partnership issued $1$1.00 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.

ETE Term Loan Facility
On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements.
Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.
On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.
In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.
Sunoco LP Term Loan
Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of December 31, 2017, the balance on the term loan was $1.24 billion.
The Sunoco LP term loan was repaid in full and terminated on January 23, 2018.
ETP5.55% Senior Notes Offering
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027February 2028 and $1.50 billion aggregate principal amount of 5.40% senior notes5.75% Senior Notes due 2047. The $2.22 billion net proceeds fromFebruary 2033.
In the offering were used to redeem allfirst quarter of 2023, the $500Partnership redeemed $350 million aggregate principal amount of ETLP’s 6.5% senior notesits 3.45% Senior Notes due 2021, to repay borrowings outstanding under the Sunoco LogisticsJanuary 2023 and $800 million aggregate principal amount of its 3.60% Senior Notes due February 2023 with proceeds from its Five-Year Credit Facility and for general partnership purposes.Facility.
Credit Facilities and Commercial Paper
Parent CompanyFive-Year Credit Facility
Indebtedness under the Parent CompanyThe Partnership’s Five-Year Credit Facility is secured by all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, but is not guaranteed by any of the Parent Company’s subsidiaries.

On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an optionallows for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advancesunsecured borrowings up to an aggregate principal amount of $1.50$5.00 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of December 31, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $312 million.
ETP Credit Facilities
On December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETPApril 11, 2027. The Five-Year Credit Facilities”).  The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitmentscommitment may be increased up to $6.0$7.00 billion under certain conditions. ETP uses the ETP Credit Facilities to provide temporary financing for its growth projects, as well as for general partnership purposes.
Borrowings under the ETP Credit Facilities are unsecured and initially guaranteed by Sunoco Logistics Partners Operations L.P.  Borrowings under the ETP Credit Facilities will bear interest at a eurodollar rate or a base rate, at ETP’s option, plus an applicable margin.  In addition, ETP will be required to pay a quarterly commitment fee to each lender equal to the product of the applicable rate and such lender’s applicable percentage of the unused portion of the aggregate commitments under the ETP Credit Facilities.  Concurrent with the closing of the ETP Credit Facilities, ETP repaid the entire amount outstanding and terminated its previously existing $3.75 billion ETLP Credit Facility and $2.50 billion Sunoco Logistics Credit Facility.
ETP typically repays amounts outstanding under the ETP Credit Facilities with proceeds from common unit offerings or long-term notes offerings. The timing of borrowings depends on ETP’s activities and the cash available to fund those activities. The repayments of amounts outstanding under the ETP Credit Facilities depend on multiple factors, including market conditions and expectations of future working capital needs, and ultimately are a financing decision made by management. Therefore, the balance outstanding under the ETP Credit Facilities may vary significantly between periods. ETP does not believe that such fluctuations indicate a significant change in its liquidity position, because ETP expects to continue to be able to repay amounts outstanding under the ETP Credit Facilities with proceeds from common unit offerings or long-term note offerings.
As of December 31, 2017,2022, the ETP Five-Year Credit Facility had $2.29 billion$793 million of outstanding borrowings, of which $2.01 billion was$750 million consisted of commercial paper. The amount available for future borrowings was $1.56$4.18 billion, after taking into accountaccounting for outstanding letters of credit in the amount of $150$32 million. The weighted average interest rate on the total amount outstanding as of December 31, 20172022 was 2.48%5.12%.
Sunoco LP Credit Facility
As of December 31, 2017,2022, the ETP 364-DaySunoco LP Credit Facility had $50$900 million of outstanding borrowings and the$7 million in standby letters of credit and matures in July 2023. The amount available for future borrowings was $950$593 million at December 31, 2022. The weighted average interest rate on the total amount outstanding as of December 31, 2022 was 6.17%.
USAC Credit Facility
As of December 31, 2022, USAC had $646 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2022, USAC had $954 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $333 million. The weighted average interest rate on the total amount outstanding as of December 31, 20172022 was 5.00%.
Sunoco Logistics Credit Facilities
ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest

owed under the revolving credit facility. As of December 31, 2017, the Sunoco LP credit facility had $9 million in standby letters of credit. The amount available for future borrowings on the revolver at December 31, 2017 was $726 million.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2017, $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%6.84%.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants, and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.
The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:
Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company (as defined) to EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7.0 to 1 during a specified acquisition period following the close of a specified acquisition; and
Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.
Covenants Related to ETP
The agreements relating to the ETP senior notesSenior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The ETPFive-Year Credit FacilitiesFacility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
•incur indebtedness;
•grant liens;
•enter into mergers;
•dispose of assets;
•make certain investments;
•make Distributions (as defined in the ETPFive-Year Credit Facilities)Facility) during certain Defaults (as defined in the ETPFive-Year Credit Facilities)Facility) and during any Event of Default (as defined in the ETPFive-Year Credit Facilities)Facility);
•engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
•engage in transactions with affiliates; and
•enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Credit Facility ranges from 0.125% to 0.300%. 
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The applicable margin for eurodollar rate loans under the ETP 364-DayFive-Year Credit Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The ETP Credit Facilities containcontains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETPFive-Year Credit FacilitiesFacility also limitlimits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements,agreement, of 5.05.00 to 1,

1.00, which can generally be increased to 5.55.50 to 11.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.963.32 to 11.00 at December 31, 2017,2022, as calculated in accordance with the credit agreements.agreement.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.
Covenants Related to Transwestern
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facilities containFacility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LPLP’s Credit Facilities  requireFacility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.

Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:
•grant liens;
•make certain loans or investments;
•incur additional indebtedness or guarantee other indebtedness;
•enter into transactions with affiliates;
•merge or consolidate;
•sell our assets; and
•make certain acquisitions.
The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:
•a minimum EBITDA to interest coverage ratio;
•a ratio (as defined therein) of not more than (a) astotal secured indebtedness to EBITDA within a specified range; and
•a maximum funded debt to EBITDA ratio.
Covenants Related to the HFOTCO Tax Exempt Notes
The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the last day of each fiscal quarter through December 31, 2017, 6.75bondholders, taking actions to 1.0, (b) as of March 31, 2018, 6.5remove the trustee, making certain amendments to 1.0, (c) as of June 30, 2018, 6.25the bond documents, and taking actions or omitting to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (intake actions that adversely impact the casetax exempt status of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities.  Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.IKE Bonds.
Compliance with our Covenants
We are required to assess compliance quarterly and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants relatingrelated to ETE’s and its subsidiaries’our debt agreements as of December 31, 2017.
Each of the agreements referred to above are incorporated herein by reference to our, ETP’s, Sunoco Logistics’ and Sunoco LP’s reports previously filed with the SEC under the Exchange Act. See “Item 1. Business – SEC Reporting.”
Off-Balance Sheet Arrangements
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.
Guarantee of Sunoco LP Notes
Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:2022.
$1.00 billion aggregate principal amount
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Contents
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligationIndex to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.Financial Statements

Contractual Obligations
The following table summarizes our long-term debt and other contractual obligations as of December 31, 2017:
  Payments Due by Period
Contractual Obligations Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years
Long-term debt $44,281
 $1,705
 $9,179
 $8,745
 $24,652
Interest on long-term debt(1)
 24,908
 2,197
 3,887
 3,081
 15,743
Payments on derivatives 223
 84
 139
 —
 —
Purchase commitments(2)
 3,605
 3,443
 99
 35
 28
Transportation, natural gas storage and fractionation contracts 25
 19
 6
 —
 —
Operating lease obligations 1,069
 113
 196
 154
 606
Other(3)
 185
 32
 56
 45
 52
Total(4)
 $74,296
 $7,593
 $13,562
 $12,060
 $41,081
(1)
Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2017. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2017. To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.
(2)
We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2017 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.
(3)
Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.
(4)
Excludes net non-current deferred tax liabilities of $3.32 billion due to uncertainty of the timing of future cash flows for such liabilities.
Cash Distributions
Cash Distributions Paid by the Parent CompanyEnergy Transfer
Under the Parent Companyits Partnership Agreement, the Parent CompanyEnergy Transfer will distribute all of its Available Cash, as defined in the Partnership Agreement, within 50 days following the end of each fiscal quarter. Available cashCash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partnerour general partner that is necessary or appropriate to provide for future cash requirements.

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

Quarter EndedRecord DatePayment DateRate
December 31, 2020February 8, 2021February 19, 2021$0.1525 
March 31, 2021May 11, 2021May 19, 20210.1525 
June 30, 2021August 6, 2021August 19, 20210.1525 
September 30, 2021November 5, 2021November 19, 20210.1525 
December 31, 2021February 8, 2022February 18, 20220.1750 
March 31, 2022May 9, 2022May 19, 20220.2000 
June 30, 2022August 8, 2022August 19, 20220.2300 
September 30, 2022November 4, 2022November 21, 20220.2650 
December 31, 2022February 7, 2023February 21, 20230.3050 
The total amounts of distributions declared and paid during the periods presented (all from Available Cash from the Parent Company’sEnergy Transfer’s operating surplus and are shown in the period to which they relate) are as follows:
 Years Ended December 31,
 20222021
Limited Partners$3,089 $1,777 
General Partner interest3 2 
Total Energy Transfer distributions$3,092 $1,779 
 Years Ended December 31,
 2017 2016 2015
Limited Partners$1,022
 $971
 $1,139
General Partner interest3
 3
 2
Class D units—
 —
 3
Total Parent Company distributions$1,025
 $974
 $1,144
Energy Transfer Preferred Unit Distributions
Cash Distributions Received by the Parent Company
The Parent Company’s cash available for distributions is primarily generated from its direct and indirect interestsAs discussed in ETP and Sunoco LP. Lake Charles LNG’s wholly-owned subsidiaries also contributeNote 8 to the Parent Company’s cash available for distributions. At December 31, 2017, our interestsconsolidated financial statements in ETP“Item 8. Financial Statements and Supplementary Data”, in connection with the Rollup Mergers, ETO’s outstanding preferred units were converted into Energy Transfer Preferred Units on April 1, 2021.
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Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and Series H preferred units declared and/or paid by Energy Transfer were as follows:
Period EndedRecord DatePayment Date
Series A (1)
Series B (1)
Series CSeries DSeries E
Series F (1)
Series G (1)
Series H (1)
March 31, 2021May 3, 2021May 17, 2021$—$—$0.4609$0.4766$0.4750$33.75$35.63$—
June 30, 2021August 2, 2021August 16, 202131.2533.130.46090.47660.4750———
September 30, 2021November 1, 2021November 15, 2021——0.46090.47660.475033.7535.6327.08*
December 31, 2021February 1, 2022February 15, 202231.2533.130.46090.47660.4750———
March 31, 2022May 2, 2022May 16, 2022——0.46090.47660.475033.7535.6332.50
June 30, 2022August 1, 2022August 15, 202231.2533.130.46090.47660.4750———
September 30, 2022November 1, 2022November 15, 2022——0.46090.47660.475033.7535.6332.50
December 31, 2022February 1, 2023February 15, 202331.2533.130.46090.47660.4750———
*    Represents prorated initial distribution.
(1)    Series A, Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A and Series B preferred units will be paid quarterly beginning after February 15, 2023 and February 15, 2028, respectively
Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well asCash Distributions
Energy Transfer owns approximately 27.5 million ETP common units, approximately 2.328.5 million Sunoco LP common units and 12 millionall of Sunoco LP’s incentive distribution rights. As of December 31, 2022, Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries.had approximately 84.1 million common units outstanding.
Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
AsThe following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of Energy Transfer Partners, L.P.’sits IDRs the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentivespecified target distribution schedulelevels, after the payment of Sunoco Logistics.distributions to Class C unitholders. The following table summarizesamounts set forth under “marginal percentage interest in distributions” are the target levels related to ETP’s distributions (as a percentage interests of total distributions on common units, IDRsthe IDR holder and the general partner interest).common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage reflected ininterests shown for common unitholders and IDR holder for the table includes onlyminimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the percentage relatedminimum quarterly distribution.
Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target AmountCommon UnitholdersHolder of IDRs
Minimum Quarterly Distribution $0.4375100%—%
First Target Distribution$0.4375 to $0.503125100%—%
Second Target Distribution$0.503125 to $0.54687585%15%
Third Target Distribution$0.546875 to $0.65625075%25%
ThereafterAbove $0.65625050%50%
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Distributions on Sunoco LP’s units declared and/or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.
paid by Sunoco LP were as follows:
Quarter EndedRecord DatePayment DateRate
Percentage of Total Distributions to IDRsETP
Quarterly Distribution Rate Target Amounts
Minimum Quarterly Distribution—%$0.0750
First Target Distribution—%up to $0.0833
Second Target Distribution13%above $0.0833 up to $0.0958
Third Target Distribution35%above $0.0958 up to $0.2638
Thereafter48%above $0.2638
Percentage of Total Distributions to IDRsSunoco LP
Quarterly Distribution Rate Target Amounts
Minimum quarterly distribution—%$0.4375
First target distribution—%$0.4375 to $0.503125
Second target distribution15%$0.503125 to $0.546875
Third target distribution25%$0.546875 to $0.656250
Fourth target distributionDecember 31, 202050%February 8, 2021Above $0.656250February 19, 2021$0.8255 
March 31, 2021May 11, 2021May 19, 20210.8255 
June 30, 2021August 6, 2021August 19, 20210.8255 
September 30, 2021November 5, 2021November 19, 20210.8255 
December 31, 2021February 8, 2022February 18, 20220.8255 
March 31, 2022May 9, 2022May 19, 20220.8255 
June 30, 2022August 8, 2022August 19, 20220.8255 
September 30, 2022November 4, 2022November 18, 20220.8255 
December 31, 2022February 7, 2023February 21, 20230.8255 

The total amount of distributions to the Parent CompanyPartnership from its limited partner interests,Sunoco LP for the periods presented below is as follows:
Years Ended December 31,
20222021
Distributions from Sunoco LP
Limited Partner interests$94 $94 
General Partner interest and IDRs72 71 
Total distributions from Sunoco LP$166 $165 
USAC Cash Distributions
Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2022, USAC had approximately 98.2 million common units outstanding. USAC currently has a non-economic general partner interest and incentiveno outstanding IDRs.
Distributions on USAC’s units declared and/or paid by USAC were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2020January 25, 2021February 5, 2021$0.5250 
March 31, 2021April 26, 2021May 7, 20210.5250 
June 30, 2021July 26, 2021August 6, 20210.5250 
September 30, 2021October 25, 2021November 5, 20210.5250 
December 31, 2021January 24, 2022February 4, 20220.5250 
March 31, 2022April 25, 2022May 6, 20220.5250 
June 30, 2022July 25, 2022August 5, 20220.5250 
September 30, 2022October 24, 2022November 4, 20220.5250 
December 31, 2022January 23, 2023February 3, 20230.5250 
The total amount of distributions (shown into the period to which they relate)Partnership from USAC for the periods ended as notedpresented below is as follows:
Years Ended December 31,
20222021
Distributions from USAC
Limited Partner interests$97 $97 
Total distributions from USAC$97 $97 
 Years Ended December 31,
 2017 2016 2015
Distributions from ETP:     
Limited Partners$61
 $28
 $54
Class H Units—
 357
 263
General Partner interest16
 32
 31
IDRs1,638
 1,363
 1,261
IDR relinquishments net of Class I Unit distributions(656) (409) (111)
Total distributions from ETP1,059
 1,371
 1,498
Distributions from Sunoco LP (1)
     
Limited Partner interests7
 7
 —
IDRs85
 81
 25
Series A Preferred23
 —
 —
Total distributions received from subsidiaries$1,174
 $1,459
 $1,523
(1)
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP. Effective January 1, 2016, ETE acquired 2,263,158 common units of Sunoco LP.
In connection with previous transactions, ETE has agreed to relinquish certain amounts of incentive distributions, including the following amounts of incentive distributions in future periods. These amounts include incentive distribution relinquishments related to both legacy ETP and legacy Sunoco Logistics, both of which are applicable to the combined post-merger ETP:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Cash Distributions Paid by Subsidiaries
Certain of our subsidiaries are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.
Cash Distributions Paid by ETP
Under ETP’s limited partnership agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”

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


The total amounts of distributions declared and paid during the periods presented (all from Available Cash from ETP’s operating surplus and are shown in the period to which they relate) are as follows:
 Years Ended December 31,
 ETP Energy Transfer Partners, L.P. Sunoco Logistics
 2017 2016 2015 2016 2015
Common Units held by public$2,435
 $2,168
 $1,970
 $485
 $344
Common Units held by ETP—
 —
 —
 135
 120
Common Units held by ETE61
 28
 54
 —
 —
Class H Units held by ETE—
 357
 263
 —
 —
General Partner interest16
 32
 31
 15
 12
Incentive distributions1,638
 1,363
 1,261
 397
 281
IDR relinquishments (1)
(656) (409) (111) (15) —
ETP Series A Preferred Units15
 —
 —
 —
 —
ETP Series B Preferred Units9
 —
 —
 —
 —
Total distributions declared to partners$3,518
 $3,539
 $3,468
 $1,017
 $757
(1)
Net of Class I unit distributions
Cash Distributions Paid by Sunoco LP
Sunoco LP is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by its general partner.
Distributions declared and paid by Sunoco LP during the periods presented were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2014 February 17, 2015 February 27, 2015 $0.6000
March 31, 2015 May 19, 2015 May 29, 2015 0.6450
June 30, 2015 August 18, 2015 August 28, 2015 0.6934
September 30, 2015 November 17, 2015 November 27, 2015 0.7454
December 31, 2015 February 5, 2016 February 16, 2016 0.8013
March 31, 2016 May 6, 2016 May 16, 2016 0.8173
June 30, 2016 August 5, 2016 August 15, 2016 0.8255
September 30, 2016 November 7, 2016 November 15, 2016 0.8255
December 31, 2016 February 13, 2017 February 21, 2017 0.8255
March 31, 2017 May 9, 2017 May 16, 2017 0.8255
June 30, 2017 August 7, 2017 August 15, 2017 0.8255
September 30, 2017 November 7, 2017 November 14, 2017 0.8255
December 31, 2017 February 06, 2018 February 14, 2018 0.8255

The total amounts of Sunoco LP distributions declared and paid during the periods presented were as follows (all from Available Cash from Sunoco LP’s operating surplus and are shown in the period with respect to which they relate):
 Years Ended December 31,
 2017 2016 2015
Limited Partners:     
Common units held by public$178
 $166
 $90
Common and subordinated units held by ETP(1)
143
 143
 89
Common and subordinated units held by ETE7
 8
 —
General Partner interest and Incentive distributions(2)
85
 81
 30
Series A Preferred23
 —
 —
Total distributions declared$436
 $398
 $209
(1)
Includes Sunoco LP units issued to ETP in connection with Sunoco LP’s acquisition of Susser from ETP in July 2015.
(2)
The Sunoco LP IDRs were held by ETP until July 2015, at which time the IDRs were exchanged with ETE. The total incentive distributions from Sunoco LP for the year ended December 31, 2015 include $5 million to ETP and 25 million to ETE related to the respective periods during which each held the IDRs.
Recent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, ETP expects that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.
We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in recognition of dealer incentives and rebates.
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.

ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
Estimates and Critical Accounting PoliciesEstimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives,
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but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for ETP’s midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices.prices for our intrastate transportation and storage segment, our midstream segment, and our NGL and refined products transportation and services segment. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 20172022 represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Revenue Recognition.  Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing, are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
The results of ETP’s intrastate transportation and storage and interstate transportation operations are determined primarily by the amount of capacity ETP’s customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Excess fuel retained after consumption is typically valued at market prices.
ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from the midstream marketing operations, and from producers at the wellhead.

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

In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Regulatory Assets and Liabilities.  Certain of our subsidiaries are subject to regulation by certain state and federal authorities and have accounting policies that conform to FASB Accounting Standards Codification (“ASC”) Topic 980, Regulated Operations, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be assessed and potentially eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Accounting for Derivative Instruments and Hedging Activities.  ETP utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit their exposure to margin fluctuations in natural gas, NGL and refined products. These contracts consist primarily of commodity futures and swaps. In addition, prior to ETP’s contribution of its retail propane activities to AmeriGas, ETP used derivatives to limit its exposure to propane market prices.
If ETP designates a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
If ETP designates a hedging relationship as a fair value hedge, they record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
ETP utilizes published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” for further discussion regarding our derivative activities.
Fair Value of Financial Instruments.  We have commodity derivatives, interest rate derivativesEstimates in Business Combination Accounting and embedded derivatives in the ETP Convertible Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our

interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable.
Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates.  Long-lived Business combination accounting and quantitative impairment testing are required from time to time due to the occurrence of events, changes in circumstances, or annual testing requirements. For business combinations, assets and liabilities are required to be recorded at estimated fair value in connection with the initial recognition of the transaction. For impairment testing, long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value. Calculating the fair value of assets or reporting units in connection with business combination accounting or impairment testing requires management to make several estimates, assumptions and judgements, and in some circumstances management may also utilize third-party specialists to assist and advise on those calculations.
In order to allocate the purchase price in a business combination or to test for recoverability when performing a quantitative impairment test, the Partnership makeswe must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, the Partnership makeswe make certain estimates and assumptions, including, among other things, changes in general economic conditions in the Partnership’s operating regions in which our markets are located, the availability and prices of natural gas, thecommodities, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers, of natural gas, and competition from other companies, including major energy producers. IfWhile we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with the Partnership’sour estimates, we could be exposed to future impairment losses that could be material may be recorded to our results of operations.
The Partnership determineddetermines the fair value of its assets and/or reporting units using a weighted combination of the discounted cash flow method, and the guideline company method.method, the reproduction and replacement methods, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our business combination accounting and impairment assessments are reasonable; however,reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determineddetermines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determineddetermines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s
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projected EBITDA and then averaging that estimate with similar historical calculations using a three yearmulti-year average. In addition, the Partnership estimatedestimates a reasonable control premium, when appropriate, representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. Under the reproduction and replacement methods, the Partnership determines the fair value of assets based on the estimated installation, engineering, and set-up costs related to the asset; these methods require the use of trend factors, such as inflation indices.
One key assumption for the measurement of an impairmentin these fair value calculations is management’s estimate of future cash flows and EBITDA. TheseIn accounting for a business combination, these estimates are generally based on the forecasts that were used to analyze the deal economics. For impairment testing, these estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwillbusiness combination accounting and impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in changes to the fair value estimates used in business combination accounting, which could significantly impact results of operations in a period subsequent to the business combination, depending on multiple factors, including the timing of such changes. In the case of impairment testing, such changes could result in additional impairments in future periods; however, management does not believe that any of the goodwill balances in its reporting units as of December 31, 2017 is at significant risk of impairment. Therefore,therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments.
In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also result in an impairment or impact the magnitude of an impairment.
During the years ended December 31, 2022, 2021 and 2020, the Partnership recorded total assets of $1.38 billion, $8.58 billion and $12 million, respectively, in connection with business combinations.
During the years ended December 31, 2022, 2021 and 2020, the Partnership recorded impairments totaling $386 million, $21 million and $3.01 billion, respectively, including $129 million in impairments in unconsolidated affiliates in 2020, and $5 million and $66 million of long-lived asset impairments in 2021 and 2020, respectively. Additional information on the impairments recorded during these periods is available in “Item 8. Financial Statements and Supplementary Data.”
Management does not believe that any of the Partnership’s goodwill balances, long-lived assets or investments in its reporting unitsunconsolidated affiliates is currently at significant risk of a material impairment; however, of the $4.8$2.57 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2017,2022, approximately $1.0 billion$368 million is recorded in ETP’s reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.
During the year ended December 31, 2017, ETP recorded following impairments:
A $223 million impairment was recorded related to the goodwill associated with CDM. In January 2018, ETP announced the contributionEstimated Useful Lives of CDM to USAC. Based on ETP’s anticipated proceeds in the contribution transaction, the implied fair value

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

During 2017, Sunoco LP announced the sale of a majority of the assets in its retail and Stripes reporting units. These reporting units include the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, Sunoco LP’s management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, Sunoco LP’s management allocated a portion of the goodwill balance previously included in the Sunoco LP retail and Stripes reporting units to assets held for sale based on the relative fair values of the business to be disposed of and the portion of the respective reporting unit that will be retained in accordance with ASC 350-20-40-3. The amount of goodwill allocated to assets held for sale was approximately $796 million and $1.1 billion as of December 31, 2017 and 2016, respectively. The remainder of the goodwill was allocated to the retained portion of the retail and Stripes reporting units, which is comprised of Sunoco LP’s ethanol plant, credit card processing services, franchise royalties and retail stores Sunoco LP continues to operate in the continental United States. This amount, inclusive of the portion of the Aloha reporting unit that represents retail activities, was approximately $678 million and $780 million as of December 31, 2017 and 2016, respectively.
Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
For goodwill included in the Aloha and Wholesale reporting units, which goodwill balances total $112 million and $732 million, respectively, and which were not classified as held for sale, no impairments were deemed necessary during 2017.
Additionally, Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.
Property, Plant and Equipment.  Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, ETP capitalizes certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the consolidated statement of operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful lives ranging from 1 to 99 years.lives. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We doThe Partnership’s results of operations have not anticipate futurebeen significantly impacted by changes in the estimated useful lives of our property, plantlong-lived assets during the periods presented, and equipment.
Asset Retirement Obligations.   We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value ofdo not anticipate any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changessuch significant changes in the liability are recorded forfuture. However, changes in facts and circumstances could cause us to change the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued useuseful lives of the assets, with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate whencould significantly impact the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the endPartnership’s results of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

Individual component assets have been and will continue to be replaced, but the pipelineoperations. Additional information on our accounting policies and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment onestimated useful lives associated with our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million of legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
Pensions and Other Postretirement Benefit Plans. We are required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. We recognize the changes in the funded status of our defined benefit postretirement plans through AOCI or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries.
The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.
The discount rate is established by using a hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced.
The expected rate of return on planlong-lived assets is based on long-term expectations given current investment objectivesavailable in “Item 8. Financial Statements and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced.Supplementary Data.”
Legal Matters.and Regulatory Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints. As of December 31, 2022 and 2021, accruals of $200 million and $144 million, respectively, were reflected in our consolidated balance sheets related to these contingent obligations.
For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.
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Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. ETP hasWe have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, ETP accrueswe accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. ETP’sThe Partnership’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded.

In addition to the probable The Partnership’s consolidated balance sheet reflected $282 million and estimable losses which have been recorded, management believes it is reasonably possible (i.e., less than probable but greater than remote) that additional$293 million in environmental remediation losses will be incurred. Ataccruals as of December 31, 2017, the aggregate of the estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics2022 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.2021, respectively.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.
Deferred Income Taxes. ETEEnergy Transfer recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal tax alternative minimum tax creditexcess business interest expense carryforwards totaling $683$603 million have been included in ETE’sEnergy Transfer’s consolidated balance sheet as of December 31, 2017. All of the deferred income tax assets attributable to state and federal NOL benefits expire before 2037 as more fully described below.2022. The state NOL carryforward benefits of $274$104 million ($21782 million net of federal benefit) begin to expirebegan expiring in 20182023 with a substantial portion expiring between 20312033 and 2037. The2039. Energy Transfer’s corporate subsidiaries have federal NOLs of $1,921 million$2.4 billion ($403496 million in benefits) of which $645 million will expire between 2036 and 2037. A total of $341 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in 2033a particular year may be limited. Any federal NOL generated in 2018 and 2036. Federal tax alternative minimum tax credit carryforwards of $62 million remained at December 31, 2017.future years can be carried forward indefinitely. We have determined that a valuation allowance totaling $236$4 million ($1863 million net of federal income tax effects) is required for the state NOLs atas of December 31, 20172022 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $15 million is attributable to foreign tax credits. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.
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Forward-Looking Statements
This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
•the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;
•the actual amount of cash distributions by our subsidiaries to us;
•the volumes transported on our subsidiaries’ pipelines and gathering systems;

•the level of throughput in our subsidiaries’ processing and treating facilities;
•the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
•the prices and market demand for, and the relationship between, natural gas and NGLs;
•energy prices generally;
•impacts of world health events, including the COVID-19 pandemic;
•the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
•the general level of petroleum product demand and the availability and price of NGL supplies;
•the level of domestic oil, natural gas and NGL production;
•the availability of imported oil, natural gas and NGLs;
•actions taken by foreign oil and gas producing nations;
•the political and economic stability of petroleum producing nations;
•the effect of weather conditions on demand for oil, natural gas and NGLs;
•availability of local, intrastate and interstate transportation systems;
•the continued ability to find and contract for new sources of natural gas supply;
•availability and marketing of competitive fuels;
•the impact of energy conservation efforts;
•energy efficiencies and technological trends;
•governmental regulation and taxation;
•changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•competition from other midstream companies and interstate pipeline companies;
•loss of key personnel;
•loss of key natural gas producers or the providers of fractionation services;
•reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;
•the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;
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•the nonpayment or nonperformance by our subsidiaries’ customers;
•regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems;
•risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
•the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;
•a deterioration of the credit and capital markets;
•risks associated with the assets and operations of entities in which our subsidiaries own less than a controllingnoncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;

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

The following tables below summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 20172022 and 20162021 for ETPthe Partnership and Sunoco LP, including derivatives related to their respectiveits consolidated subsidiaries. Dollar amounts are presented in millions.
December 31, 2022December 31, 2021
Notional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% ChangeNotional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures145 $— $— 585 $— $— 
Basis Swaps IFERC/NYMEX(1)
(39,563)54 3 (66,665)(5)1 
Power (Megawatt):
Forwards— 1 — 653,000 2 — 
Futures(21,384)— — (604,920)2 2 
Options – Puts119,200 — — (7,859)— — 
Options – Calls— — — (30,932)— — 
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX42,440 (41)4 6,738 1 1 
Swing Swaps IFERC(202,815)63 7 (106,333)32 31 
Fixed Swaps/Futures(15,758)51 7 (63,898)(24)38 
Forward Physical Contracts2,423 8 1 (5,950)1 — 
NGL (MBbls) – Forwards/Swaps6,934 (41)63 8,493 12 19 
Crude (MBbls) – Forwards/Swaps795 26 22 3,672 13 2 
Refined Products (MBbls) – Futures(3,547)(39)37 (3,349)(15)32 
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX(37,448)22 2 (40,533)1 — 
Fixed Swaps/Futures(37,448)58 17 (40,533)41 14 
 December 31, 2017 December 31, 2016
 Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change
Mark-to-Market Derivatives           
(Trading)           
Natural Gas (BBtu):           
Fixed Swaps/Futures1,078
 $—
 $—
 (683) $—
 $—
Basis Swaps IFERC/NYMEX(1)
48,510
 2
 1
 2,243
 (1) —
Options – Puts13,000
 —
 —
 —
 —
 —
Power (Megawatt):           
Forwards435,960
 1
 1
 391,880
 (1) 1
Futures(25,760) —
 —
 109,564
 —
 —
Options — Puts(153,600) —
 1
 (50,400) —
 —
Options — Calls137,600
 —
 —
 186,400
 1
 —
Crude (MBbls) — Futures—
 1
 —
 (617) (4) 6
(Non-Trading)           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX4,650
 (13) 4
 10,750
 2
 —
Swing Swaps IFERC87,253
 (2) 1
 (5,663) (1) 1
Fixed Swaps/Futures(4,390) (1) 2
 (52,653) (27) 19
Forward Physical Contracts(145,105) 6
 41
 (22,492) 1
 —
Natural Gas Liquid (MBbls) — Forwards/Swaps6,744
 1
 25
 (5,787) (40) 35
Refined Products (MBbls) — Futures(3,901) (27) 4
 (3,144) (21) 18
Corn (Bushels) – Futures1,870,000
 —
 —
 1,580,000
 —
 1
Fair Value Hedging Derivatives           
(Non-Trading)           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX(39,770) (2) —
 (36,370) 2
 1
Fixed Swaps/Futures(39,770) 14
 11
 (36,370) (26) 14
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the belowabove tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the
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contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfoliosportfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Interest Rate Risk
As of December 31, 2017, we and2022, our subsidiaries had $9.86$3.16 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $98$32 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, none of which arewere designated as hedges for accounting purposes:purposes (dollar amounts presented in millions):
Term
Type(1)
Notional Amount Outstanding
December 31, 2022December 31, 2021
July 2022 (2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate$— $400 
July 2023 (2)(3)
Forward-starting to pay a fixed rate of 3.845% and receive a floating rate— 200 
July 2024 (2)
Forward-starting to pay a fixed rate of 3.512% and receive a floating rate400 200 
  
     Notional Amount Outstanding
Entity Term 
Type(1)
 December 31, 2017 December 31, 2016
ETP 
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
ETP 
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
ETP 
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
ETP 
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
ETP December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
ETP March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1)Floating rates are based on either SOFR or three-month LIBOR.
(1)
(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
(3)This interest rate swap was terminated and settled in 2022.
Floating rates are based on 3-month LIBOR.
(2)
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of the interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of approximately $236$73 million as of December 31, 2017. For ETP’s $1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow of $15 million.2022. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
TheOur natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers,industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements starting on page F-1 of this report are incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of our management, including the PresidentMarshall S. McCrea, III and Group Chief Financial OfficerThomas E. Long, Co-Chief Executive Officers of our General Partner (Co-Principal Executive Officers), and Dylan A. Bramhall (Principal Financial Officer), of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the PresidentMessrs. McCrea, Long and Group Chief Financial Officer of our General Partner,Bramhall, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2017.2022.
Management’s Report on Internal Control over Financial Reporting
The management of Energy Transfer Equity, L.P.LP and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the PresidentCo-Chief Executive Officers and Group Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).
Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2017.2022.
Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2017,2022, as stated in their report, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer Equity, L.P.LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Energy Transfer Equity, L.P.LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017,2022, based on criteria established in the 2013 Internal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2022, based on criteria established in the 2013 Internal Control-IntegratedControl—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2017,2022, and our report dated February 23, 201817, 2023 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.
We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ GRANT THORNTON LLP

Dallas, Texas
February 23, 201817, 2023

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Changes in Internal Controls over Financial Reporting
There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 20172022 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION
None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of ETEEnergy Transfer are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement.
As of December 31, 2017,January 1, 2023, our Board of Directors wasis comprised of sevennine persons, threefour of whom qualify as “independent” under the NYSE’s corporate governance standards. As a limited partnership, we are not required under the NYSE’s corporate governance standards (Section 303A) to have a majority of independent directors. We have determined that Messrs. Anderson, Brannon, TurnerGrimm and WilliamsPerry are all “independent” under the NYSE’s corporate governance standards.
As a limited partnership, we are not required by the rules of the NYSE to seek unitholderUnitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of the Parent Company,Energy Transfer, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of Energy Transfer.
Board Leadership Structure. We have no policy requiring either that the Parent Company.positions of the Chairman of the Board and the Chief Executive Officer, or CEO, be separate or that they be occupied by the same individual. The Board of Directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances. Previously, the Board of Directors believed that the CEO was best situated to serve as Chairman because he was the director most familiar with the Partnership’s business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Beginning in 2021, the Board of Directors has established separate roles for the Executive Chairman and Co-Chief Executive Officers. Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and from a variety of industries, while the Executive Chairman and Co-Chief Executive Officers bring extensive experience and expertise specifically related to the Partnership’s business.
Risk Oversight
. Our Board of Directors generally administers its risk oversight function through the board as a whole. Our President,Co-CEOs, who reportsreport to the Board of Directors, hashave day-to-day risk management responsibilities. Our President attendsCo-CEOs attend the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Parent Company’sEnergy Transfer’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Parent Company’sEnergy Transfer’s internal auditor, who reports directly to the Audit Committee, and reviews the Parent Company’sEnergy Transfer’s contingencies with management and our independent auditors.
Corporate Governance
The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.
Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.
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Annual Certification
In 2017,2022, our PresidentChief Executive Officer provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards.
Conflicts Committee
Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to the Parent CompanyEnergy Transfer and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Parent CompanyEnergy Transfer to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to the Parent Company.Energy Transfer. Pursuant to the terms of our partnership agreement,Partnership Agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Parent Company,Energy Transfer, approved by all partners of the Parent CompanyEnergy Transfer and not a breach by the general partner or its Board of Directors of any duties

they may owe the Parent CompanyEnergy Transfer or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Audit Committee
The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Rick TurnerMichael K. Grimm qualified as an audit committee financial expert during 2017.2022. A description of the qualifications of Mr. TurnerGrimm may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”
The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and makes recommendations toapproves the Boardfiling of Directors relating toour Form 10-K, which includes our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of ETEEnergy Transfer be included in ETE’sEnergy Transfer’s Annual Report on Form 10-K for the year ended December 31, 2017.2022.
The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Rick Turner and William P. WilliamsGrimm serve as elected members of the Audit Committee.
Compensation and Nominating/Corporate Governance Committees
Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Pursuant to the CharterMessrs. Anderson and Grimm serve as members of the Compensation Committee, a director serving as a member of the Compensation Committee may not be an officer of or employed by our general partner, the Parent Company, ETP or its subsidiaries, or Sunoco LP or its subsidiaries.
Matters relating to the nomination of directors or corporate governance matters were addressed to and determined by the full Board of Directors for the period ETE did not have a compensation committee.Committee.
The responsibilities of the ETEEnergy Transfer Compensation Committee include, among other duties, the following:
•annually review and approve goals and objectives relevant to compensation of our PresidentCo-CEOs and CFO, if applicable;
•annually evaluate the PresidentCEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the PresidentCEO and CFO’s compensation levels, if applicable, based on this evaluation;
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•make determinations with respect to the grant of equity-based awards to executive officers under ETE’sEnergy Transfer’s equity incentive plans;
•periodically evaluate the terms and administration of ETE’sEnergy Transfer’s long-term incentive plans to assure that they are structured and administered in a manner consistent with ETE’sEnergy Transfer’s goals and objectives;
•periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
•periodically evaluate the compensation of the directors;

•retain and terminate any compensation consultant to be used to assist in the evaluation of director, PresidentCEO and CFO or executive officer compensation; and
•perform other duties as deemed appropriate by the Board of Directors.
Code of Business Conduct and Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the principalco-principal executive officer,officers, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.
Meetings of Non-management Directors and Communications with Directors
Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.
We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer Equity, L.P.,LP, 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.
Directors and Executive Officers of Our General Partner
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of February 23, 2018.17, 2023. Executive officers and directors are elected for indefinite terms.
NameAgePosition with Our General Partner
John W. McReynolds67
Director and President
Kelcy L. Warren6267 
Director andExecutive Chairman of the Board of Directors
Thomas E. Long6166 
Group Chief FinancialCo-Chief Executive Officer and Director (Co-Principal Executive Officer)
Marshall S. (Mackie) McCrea, III5863 
Co-Chief Executive Officer and Director and (Co-Principal Executive Officer)
Dylan A. Bramhall46 Group Chief OperatingFinancial Officer and Chief Commercial Officer(Principal Financial Officer)
Thomas P. Mason6166 
Executive Vice President and General CounselPresident - LNG
BradBradford D. Whitehurst4348 
Executive Vice President and Head of Tax and Corporate Initiatives
James M. Wright, Jr.54 Executive Vice President, General Counsel and Chief Compliance Officer
A. Troy Sturrock52 Group Senior Vice President and Controller (Principal Accounting Officer)
Steven R. Anderson73 Director
Richard D. Brannon5964 
Director
Michael K. Grimm68 Director
John W. McReynolds72 Director
James R. (Rick) Perry72 Director
Matthew S. Ramsey6267 
Director
K. Rick Turner59
Director
William P. Williams80
Director
Messrs. Warren,Mr. Long, Mr. Mason and McCrea also serve as directors of ETP’s general partner. Messrs. Ramsey and TurnerMr. Whitehurst serve as directors of the general partner of Sunoco LP.USAC.
Set forth below is biographical information regarding the foregoing officers and directors of our general partner:
John W. McReynolds
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Kelcy L. Warren. Mr. McReynolds hasWarren serves as Executive Chairman of our general partner. Mr. Warren served as our President since March 2005, and as a Director since August 2005. He served as our Chief FinancialExecutive Officer from August 2005 to June 2013, and previously served as a Director of ETP from August 20012007 through May 2010. Mr. McReynolds has been in the energy industry for his entire career. Prior to becoming President and CFO of ETE, Mr. McReynolds was in private law practice for over 20 years,  specializing exclusively in energy-related finance, securities, corporations and partnerships, mergers and acquisitions, syndications, and a wide variety of energy-related litigation. His practice dealt with all forms of fossil fuels, and the transportation and handling thereof, together with the financing and structuring of all forms of business entities related thereto. The members of our general partner selected Mr. McReynolds to serve in the indicated roles with the Energy Transfer partnerships because of this extensive background and experience, as well as his many contacts and relationships in the industry.
Kelcy L. Warren.  Mr. WarrenDecember 2020. He was appointed Co-Chairman of the Board of Directors of our general partner, LE GP, LLC, effective upon the closing of our IPO. OnIPO, and in August 15, 2007, Mr. Warrenhe became the sole Chairman of the Board of our general partner and

the Chief Executive Officer and Chairman of the Board of the general partner of ETP.ETO until its merger into Energy Transfer LP in April 2021. Prior to that,August 2007, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETPETO since the combination of the midstream and intrastate transportation storage operations of ETC OLPLa Grange Acquisition, L.P. and the retail propane operations of Heritage in January 2004. Mr. Warren also serves as Chief Executive Officer of the general partner of ETC OLP. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Warren served as President of the general partner of ET Company I, Ltd. the entity that operated ETP’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he also served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 30 years of business experience in the energy industry. The members of our general partnerwas selected Mr. Warren to serve as a director and as Executive Chairman because he is ETP’spreviously served as Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States and brings a unique and valuable perspective to the Board of Directors.
Thomas E. Long. Mr. Long ishas served as the GroupCo-Chief Executive Officer of our general partner since January 2021. Mr. Long served as Chief Financial Officer of ETEEnergy Transfer’s general partner from February 2016 until January 2021, and has been a director of our general partner since February 2016.April 2019. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long has served as a director of Sunoco LP since May 2016. Mr. Long previouslyalso served as Chief Financial Officer of ETPETO until its merger into Energy Transfer LP in April 2021, and aswas previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice Presidenta director of Sunoco LP from May 2016 until May 2021, and Chief Financial Officerhas served on the Board of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners, LP, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, CO.USAC since April 2018. In that position, he was responsible for all financial aspects of the company since its formation in December 2005. From 1998 to 2005,May 2022, Mr. Long servedwas appointed to the board of directors of Texas Capital Bancshares, Inc (NASDAQ: TCBI). Mr. Long was selected to serve on our Board of Directors because of his understanding of energy-related corporate finance gained through his extensive experience in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies.energy industry.
Marshall S. (Mackie) McCrea, III. Mr. McCrea ishas served as the Co-Chief Executive Officer of our general partner since January 2021. Prior to that he was the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer forof the Energy Transfer family andsince November 2015. Mr. McCrea has served in that capacityon the Board of Directors of our general partner since November 2015.December 2009. Mr. McCrea was appointed as a director of the general partner of ETPETO in December 2009.2009 and served in that capacity until ETO’s merger into Energy Transfer LP in April 2021. Prior to that,December 2009, he served as President and Chief Operating Officer of ETP’sETO’s general partner from June 2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETP’sETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also currently serves on the Board of Directors of the general partner of ETE. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017. The members of our general partner selected Mr. McCrea was selected to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.
Dylan A. Bramhall. Mr. Bramhall has served as Group Chief Financial Officer of our general partner since November 2022 and currently is also Chief Financial Officer of Sunoco LP’s general partner. Mr. Bramhall joined Energy Transfer in 2015 as a result of its merger with Regency Energy Partners and is responsible for oversight of the Partnership’s Financial Planning and Analysis, Credit and Commodity Risk Management, Insurance, Cash Management, Capital Markets, Accounting, Financial Reporting and Investor Relations groups. He also serves as a member of Energy Transfer’s Risk Oversight Committee. While at Regency, Mr. Bramhall held management positions in the finance, risk, commercial and operations groups. Mr. Bramhall holds a Bachelor of Business Administration in finance and Master of Business Administration in finance and operations management, both from the University of Iowa.
Thomas P. Mason.Mr. Mason has served as Executive Vice President and President - LNG since December 2022. He became Executive Vice President and General Counsel of the general partner of ETEEnergy Transfer in December 2015.2015, and served as the Executive Vice President, General Counsel and President - LNG from October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. until December 2022 when he resigned from his role as General Counsel. In February 2021, Mr. Mason also served as a directorassumed leadership responsibility over the Partnership’s newly created Alternative Energy Group, which focuses on the development of PennTex Midstream Partners, LP’s general partner from November 2016alternative energy projects aimed at continuing to July 2017.reduce Energy Transfer’s environmental footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETP’sETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETP,Energy Transfer, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also served as a director on the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017.2017 and as a director on the Board of Directors of PennTex Midstream
Brad
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Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason has also served as a member of the Board of Directors of USAC since April 2018.
Bradford D. Whitehurst.Mr. Whitehurst has served as the Executive Vice President of Tax and Corporate Initiatives of Energy Transfer since November 2022. From January 2021 to November 2022, he served as Chief Financial Officer. From August 2014 through December 2020, he served as Executive Vice President – Head of Tax of our general partner since August 2014.Tax. Prior to joining ETE,Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised ETEEnergy Transfer and its subsidiaries in his role as outside counsel since 2006. He has served as a member of the board of directors of USAC since April 2019.
James M. Wright, Jr. Mr. Wright was appointed as Executive Vice President, General Counsel and Chief Compliance Officer of our general partner in December 2022. He became Executive Vice President - Legal and Chief Compliance Officer of ET’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Wright has been a part of the Energy Transfer legal team with increasing levels of responsibility since July 2005 and has held various senior-level positions in the legal department including General Counsel of the general partner of Energy Transfer Partners, L.P. from December 2015 to October 2018 and Deputy General Counsel from May 2008 to December 2015. Prior to joining Energy Transfer, Mr. Wright gained significant experience at Enterprise Products Partners, L.P., El Paso Corp., Sonat Exploration Company and KPMG Peat Marwick LLP. Mr. Wright earned a Bachelor of Business Administration degree in Accounting and Finance from Texas A&M University and a JD from South Texas College of Law.
A. Troy Sturrock. Mr. Sturrock has served as the Group Senior Vice President, Controller and Principal Accounting Officer of our general partner since September 2022. He previously served as Senior Vice President, Controller and Principal Accounting Officer, having assumed that role in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He served as the Senior Vice President, Controller and Principal Accounting Officer of the general partner of ETO from August 2016 until ETO’s merger into Energy Transfer LP in April 2021, and previously served as Vice President, Controller and Principal Accounting Officer of our general partner beginning in June 2015. Mr. Sturrock is a Certified Public Accountant.
Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon’s Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. Mr. Anderson also served as a member of the board of directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. Mr. Anderson was selected to serve on our Board of Directors based on his experience in the midstream energy industry generally, and his knowledge of Energy Transfer’s business specifically. Mr. Anderson also brings recent experience on audit and compensation committees of another publicly traded partnership.
Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the audit committee since April 2016. Previously, heMr. Brannon is the CEO of CH4 Energy Six, LLC and Uinta Wax, LLC, both independent companies focused on horizontal oil and gas development. Mr. Brannon previously served on the Sunoco LP Boardboard of Directors from September 2014 to March 2016. Mr. Brannon has also served on the Board of Directorsdirectors of WildHorse Resource Development Corp. (NYSE: WRD), sincefrom its IPO in December 2016 he is CEO of CH4 Energy II, III, IV, V and VI, all independent companies focused on horizontal development of oil and gas. Previously, he was President of CH4 Energy Corp. from 2001 to 2006, when the company was sold to Bill Barrett Corp. From 1984 to 2005, Dick was President of Brannon Oil & Gas, Inc. and Brannon & Murray Drilling Co. Previously, he was a drilling and completion engineer for Texas Oil & Gas Corp. He has previously served on the boards of Cornerstone Natural Gas Corp., which was purchased by El Paso Corp. in 1996, and OEC Compression Corp, acquired by Hanover Compressor Company in 2001.until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Sunoco LP, Regency, Energy Partners LPOEC Compression and Sunoco LP.Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business, having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.
Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and served on the audit and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held upstream exploration and production company active in onshore continental United States, and served as its President and Chief Executive Officer from 1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018. From November 2018 until it was sold in 2019, Mr. Grimm served on the Board of Directors of Anadarko Petroleum Corporation. Prior to the formation of Rising Star,
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Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr. Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the American Association of Professional Landmen, Dallas Wildcat Committee, Dallas Producers Club, and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. Mr. Grimm was selected to serve as a director because of his extensive experience in the energy industry experience and his service as a senior executive at several energy-related companies, in addition to his contacts in the industry gained through his involvement in energy-related organizations.
John W. McReynolds. Mr. McReynolds is a director of Energy Transfer LP, having served in that capacity since August 2004. Mr. McReynolds previously served as the President of Energy Transfer LP from March 2005 until October 2018, at which time he became Special Advisor to the Partnership. Mr. McReynolds also previously served as our Chief Financial Officer from August 2005 to June 2013. Prior to becoming President of Energy Transfer LP, Mr. McReynolds was a partner in the international law firm of Hunton & Williams LLP for over 20 years. As a lawyer, he specialized in energy related finance, securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation, and governmental proceedings, including as an expert in special projects for boards of directors of public companies. Mr. McReynolds was selected to serve in the indicated roles with Energy Transfer because of this extensive background and experience, as well as his many contacts and relationships in the industry.
James R. (Rick) Perry. Mr. Perry was appointed to the Board of Directors of our general partner in January 2020. He formerly served as U.S. Secretary of Energy from March 2017 until December 2019. Prior to that, he served as the Governor of the State of Texas from 2000 until January 2015. Mr. Perry served as Lieutenant Governor of Texas from 1998 to 2000, and as Agriculture Commissioner from 1991 to 1998. Prior to 1991, he also served in the Texas House of Representatives. Mr. Perry previously served on other public company boardsthe Board of Directors of ETO from February 2015 until December 2016. Mr. Perry was selected to serve as a director because of his vast experience as an executive in the highest office of state government. In addition, Mr. Perry has been involved in finance and committees.budget planning processes throughout his career in government as a member of the Texas House Appropriations Committee, the Legislative Budget Board and as Governor.

Matthew S. Ramsey. Mr. Ramsey was appointed as a director of ETE’sEnergy Transfer’s general partner onin July 17, 2012 and served as a director of ETP’sETO’s general partner onfrom November 9, 2015.2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey currently servesserved as the Chief Operating Officer or our general partner from October 2018 until his retirement in April 2022, and served as President and Chief Operating Officer of ETP’sETO’s general partner sincefrom November 2015.2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey is also previously served as a director of Sunoco LP, servinghaving served as chairman of Sunoco LP’s board sincefrom April 2015.2015 until March 2022, and of USAC, having served on that board from April 2018 until March 2022. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, generating and drilling 3-D seismic prospects on the Gulf Coast of Texas. Mr. Ramsey is currentlypreviously served as a director of RSP Permian, Inc. (NYSE: RSPP), where he served on the audit and compensation committees. In addition to his work in the energy business, Mr. Ramsey serves as chairmanon the board of directors of the compensation committeeNational Association of Manufacturers and as a memberTrustee of the audit committee. Mr. Ramsey formerly served as PresidentSouthwestern Medical Foundation. He is the former Chairman of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officerthe University of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992.Texas Chancellor’s Council. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business School Advanced Management Program. Mr. Ramsey is licensedwas selected to practice law in the State of Texas. He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a director of Southern Union Company. The member of our general partner recognize Mr. Ramsey’sserve based on vast experience in the oil and gas space and believeEnergy Transfer believes that he provides valuable industry insight as a member of our Board of Directors.
K. Rick Turner.  Mr. Turner has served as a director of our general partner since October 2002. Mr. Turner currently serves as chair of the Compensation Committee and a member of the Audit Committee. Mr. Turner is also a director of Sunoco LP, serving as chair of Sunoco LP’s compensation and audit committees. Mr. Turner is presently a managing director of Altos Energy Partners, LLC. Mr. Turner previously was a private equity executive with several groups after retiring from the Stephens’ family entities, which he had worked for since 1983. He first became a private equity principal in 1990 after serving as the Assistant to the Chairman, Jackson T. Stephens. His areas of focus have been oil and gas exploration, natural gas gathering, processing industries, and power technology. Prior to joining Stephens, he was employed by Peat, Marwick, Mitchell and Company. Mr. Turner currently serves as a director of AmeriGas Partners, L.P. Mr. Turner earned his B.S.B.A. from the University of Arkansas and is a non-practicing Certified Public Accountant. The members of our general partner selected Mr. Turner based on his industry knowledge, his background in corporate finance and accounting, and his experience as a director and audit committee member on the boards of several other companies.
William P. Williams. Mr. Williams was appointed as a director in March 2012 and currently serves as a member of the Audit Committee. Mr. Williams began his career in the oil and gas industry in 1967 with Texas Power and Light Company as Manager of Pipeline Construction for Bi-Stone Fuel Company, a predecessor of Texas Utilities Fuel Company. In 1980, he was employed by Endevco as Vice President of Pipeline and Plant Construction, Engineering, and Operations. Prior to Endevco, he worked for Cornerstone Natural Gas. Mr. Williams later joined Energy Transfer Partners, L.P. as Vice President of Engineering and Operations, ending his career as Vice President of Measurement in May 2011. The members of our general partner selected Mr. Williams due to his experience in the pipeline industry and his familiarity with our business.
Compensation of the General Partner
Our general partner does not receive any management fee or other compensation in connection with its management of the Parent Company.
Delinquent Section 16(a) Beneficial Ownership Reporting ComplianceReports
Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2017.2022, with the exception of one late Form 4 each for Messrs. Wright, Brannon and McReynolds.

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ITEM 11. EXECUTIVE COMPENSATION
Overview
As a limited partnership, we are managed by our General Partner. Our General Partner is majority owned by Mr. Kelcy Warren.
We own 100% of ETP GP and its general partner, ETP LLC. We refer to ETP GP and ETP LLC together as the “ETP GP Entities.” ETP GP is the general partner of ETP. All of ETP’s employees receive employee benefits from the operating companies of ETP.
We acquired 100% of Sunoco GP LLC, the general partner of Sunoco LP, from ETP in July 2015. All of Sunoco LP’s employees receive employee benefits from either Sunoco GP LLC or the operating companies of Sunoco LP.
Compensation Discussion and Analysis
Named Executive Officers
ETEEnergy Transfer does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of ETE’sEnergy Transfer’s management functions. As a result, the executive officers of our General Partner are essentially ETE’sEnergy Transfer’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. In addition, to provide comprehensive disclosure of our executive compensation, we are also providing information as to the executive compensation of certain executive officers of our subsidiaries, even though none of these persons is an executive officer of the Parent Company. Accordingly, theThe persons we refer to in this discussion as our “named executive officers” are the following:
ETE Executive Officers
John W. McReynolds, President;
Thomas E. Long, Chief Financial Officer and Group Chief Financial Officer of ETE’s general partner;
•Marshall S. (Mackie) McCrea, III, Co-Chief Executive Officer;
•Thomas E. Long, Co-Chief Executive Officer;
•Dylan A. Bramhall, Executive Vice President and Group Chief Operating OfficerFinancial Officer;
•Bradford D. Whitehurst, Executive Vice President — Tax and Chief Commercial Officer;Corporate Initiatives;
•Thomas P. Mason, Executive Vice President — Alternative Energy and General Counsel;President — LNG; and
Bradford D. Whitehurst,•James M. Wright, Jr., Executive Vice President, General Counsel and Head of Tax.Chief Compliance Officer.
Our Philosophy for Compensation of Executives
Our General Partner.In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for its executive officers, including the named executive officers, that provides for a slightly below the median market annual base compensation rate (i.e., approximately the 30th to 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both shortshort- and long-term performance that are both targeted to pay-outpay out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by the payment of annual discretionary cash bonuses and grants of restricted unit awards. Our General Partner believes the performance of our operating subsidiaries and the contribution of our management toward the achievement of the financial targets and other goals of those subsidiaries should be considered in determining annual discretionary cash bonuses.
ETP GP Entities. The ETP GP Entities also believe that a significant portion of each executives’ compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be very competitive in the marketplace for executive talents and abilities. ETP GP seeks a total compensation program for the named executive officers that provides for a slightly below the median market annual base compensation rate (i.e. approximately the 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. ETP GP believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of ETP’sthe Partnership’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its executive officers, including the named executive officers, to the success of ETPthe Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit, or phantom unit awards or cash restricted unit awards under ETE’s equity incentive plan, ETP’sthe Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of executive officers awards, including awards to the named executive officers’ award,officers, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution ETPthe Partnership and/or the other affiliated partnerships pay to their respective unitholders.

The Partnership grantshas historically granted restricted unit/unit and/or phantom unit awards (“RSUs”) that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. Beginning in 2020, Energy Transfer began granting cash restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. For 2020, the awards to employees were generally split equally between RSUs and CRSUs; for 2021 and 2022, the awards were generally split based on 75% RSUs and 25% CRSUs. The ETP GP Entities believePartnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance ETP GPour General Partner places on aligning the interests of its named executive officers with those of unitholders.
Unitholders. While ETE, through the ETP GP Entities,Partnership utilizes time-based forms of equity awards, the grant date valuation utilizes a modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is responsible for the direct paymentdesigned to create a recognition of the compensation of our named executive officers, ETE does not participate or have any input in any decisions asa performance adjustment to the compensation levels or policiesequity awards based on the prior periods measured to add an element of our General Partner orperformance impact in setting grant date value even though the ETP GP Entities. RSUs and CRSUs themselves are a time-vested vehicle.
As discussed below, our compensation committee the eligible members of board of directors of our General Partner at times when we have not had a compensation committee or the ETP Compensation Committee and/or the compensation committee of the general partner of Sunoco Logistics and Sunoco LP, as applicable, all in consultation with theour General Partner, are responsible for the compensation policies and compensation level of our executive officers, including the named executive officers of our General Partner. In this discussion, we refer to either or both of the ETE Compensation Committee or such members of our board of directors collectivelycompensation committee as the “ETE“Energy Transfer Compensation Committee.”
ETP also does not participate or have any input in any decisions as
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Sunoco LP also does not participate or have any input in any decisions as to the compensation policies of Sunoco GP LLC or the compensation levels of the executive officers of its general partner. The SUN Compensation Committee is responsible for the approval of the compensation policies and the compensation levels of the executive officers of Sunoco GP LLC.
For a more detailed description of the compensation to ETE’s and ETP GP’sthe Partnership’s named executive officers, please see “– Compensation Tables” below.
Distributions to Our General Partner
Our General Partner is partially-ownedmajority-owned by certain of our current and prior named executive officers.Mr. Kelcy Warren. We pay quarterly distributions to our General Partner in accordance with our partnership agreementPartnership Agreement with respect to its ownership of its general partner interest as specified in our partnership agreement.Partnership Agreement. The amount of each quarterly distribution that we must pay to our General Partner is based solely on the provisions of our partnership agreement, which agreement specifies the amount of cash we distribute to our General Partner based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per unitper-unit distributions equal the per unitper-unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees.
For a more detailed description of the compensation of our named executive officers, please see “Compensation“– Compensation Tables” below.
Compensation Philosophy
Our compensation programs are structured to achieve the following:
•reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;
•attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships or other peer companies of similar size and in similar lines of business;
•motivate executive officers and key employees to achieve strong financial and operational performance;
•emphasize performance-based, or “at-risk”“at-risk,” compensation; and
•reward individual performance.

Components of Executive Compensation
For the year ended December 31, 2017,2022, the compensation paid to our named executive officers consisted of the following components:
•annual base salary;
•non-equity incentive plan compensation consisting solely of discretionary cash bonuses;
•time-vested restricted/phantom unit awardsRSUs and CRSUs under the equity incentive plan(s);
•payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit awardRSUs under our equity incentive plan;
•vesting of previously issued time-based restricted unit/phantom restricted unit awardsRSUs issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and
•401(k) plan employer contributions.
Methodology
The ETEEnergy Transfer Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The ETEEnergy Transfer Compensation Committee also considers individual performance, levels of responsibility, skills and experience.
Periodically, the ETE or ETPEnergy Transfer Compensation Committee engages a third-party independent compensation consultant to provide a full market informationcompetitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, Longnecker & Associatesin 2021 Meridian Compensation Partners, LLC (“Longnecker”Meridian”) evaluatedcompleted an evaluation of the market competitiveness of total compensation levels of a number of officers of ETE and ETP to providethe Partnership, including the named executive officers. The Meridian review provided market information with respect to compensation of thosePartnership executives, including named executive officers during the year ended December 31, 2017.2021. In particular, the review by LongneckerMeridian was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive
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officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. The Partnership continued to rely on the Meridian review for calendar year 2022.
In conducting its review, Longnecker specifically considered the larger size of the combined ETE and ETP entities from an energy industry perspective. During 2017, LongneckerMeridian assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of ETP and ETEEnergy Transfer. The final “peer group” consisted of the core group of peers (i.e. the eight most similar peers in terms of business, revenues, assets and market value as well as competition for talent at the senior management levellevel) and similarly situated general industrya group of expanded reference companies with similar revenues, assetscomposed of a broader group of oil and gas companies, including additional integrated, upstream and midstream comparators whose data provided additional market value. In setting such peer group,context. As part of the size of ETE and ETP on a combined basis was considered. Unlike in prior evaluationsevaluation conducted by Longnecker,Meridian, a determination was made to focus the analysis specificallylargely on the core energy industry peers. This decision was based on a determination that an energy industrythe core peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This decisionfocus allowed LongneckerMeridian to report on this specific industry relatedcore peer data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies.companies, while at the same time considering whether the context provided by the expanded group offered additional information that should be considered by the Compensation Committee. The core identified companies were:
Energy Peer Group:
• Conoco Phillips• AnadarkoMarathon Petroleum Corporation
• Enterprise Products Partners, L.P.• Marathon Petroleum CorporationKinder Morgan, Inc.
• Plains All American Pipeline, L.P.• Kinder Morgan, Inc.
• Halliburton Company• The Williams Companies, Inc.
• Valero Energy Corporation• Phillips 66
The compensation analysis provided by Longnecker in 2017Meridian covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives of these companies.executives. In preparing the review materials, LongneckerMeridian utilized generally accepted compensation principles as determined by WorldatWork and gathered data from the public disclosures of peer companies, including Form 10-K and proxy data and published salary surveys.

survey data from multiple sources that are relevant to Energy Transfer’s core peer group, industry, financial size and operational breadth. The Meridian review process also included significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow Meridian the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.
Following Longnecker’s 2017Meridian’s 2021 review, the ETEEnergy Transfer Compensation Committee reviewed the information provided, including Longnecker’sMeridian’s specific conclusions and recommended considerations for all compensation going forward. The ETEEnergy Transfer Compensation Committee considered and reviewed the results of the study performed by LongneckerMeridian to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Longnecker’sMeridian’s conclusions and recommendations. While LongneckerMeridian found that ETEthe Partnership is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments shouldcould be implementedconsidered moving forward to allow ETEthe Partnership to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). Certain of Meridian’s suggested adjustments as described below.part of the review were implemented and others were determined to require additional review and consideration.
In addition to the information received as part of Meridian’s review, the Energy Transfer Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third-party surveys, although third-party survey data is not used by the Energy Transfer Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers.
Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e., approximately the 30th to 40th percentile of market) and are determined by the ETEEnergy Transfer Compensation Committee after taking into account the recommendations of Mr. Warren.
During the 2017 merit review process, the ETEEnergy Transfer Compensation Committee consideredconsiders the recommendations of Mr. Warren, any relevant compensation study data (with the results of the Longnecker studydata aged as appropriate) and the merit increase pool set for all employees of ETP GP and ETP. The ETEthe Partnership and/or its employing affiliates. During 2022, the Energy Transfer Compensation Committee approved an a 4%
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increase to the base salary of Mr. McReynolds of 2.5%McCrea to $598,026$1,399,320 from itsthe prior level of $583,440;$1,345,500; a 2.5%4% increase to the base salary increase of Mr. McCreaLong to $1,045,000$1,399,320 from its priorthe previous level of $1,020,000; and a 2.5%$1,345,500; an approximately 4% increase to the base salary of Mr. Whitehurst to $640,425 from the previous level of $615,825; and an approximately 4% increase to the base salary of Mr. Mason to $592,276$679,695 from the previous level of $653,495.
In connection with his promotion to Group Chief Financial Officer effective November 11, 2022, the Energy Transfer Compensation Committee had previously approved an increase in the annual base salary of Mr. Bramhall to $575,000 from its priorprevious level of $577,830.$425,000. In connection with his promotion to General Counsel effective November 30, 2022, the case of Mr. Long, the ETEEnergy Transfer Compensation Committee approved an increase to Mr. Long’sin the annual base salary of Mr. Wright to $530,000$550,000 from its priorprevious level of $459,000, which represents an approximately 15.5% increase and was based largely on the recommendation of Mr. Warren and the results of the Longnecker study. In the case of Mr. Whitehurst, the ETE Compensation Committee approved an increase to Mr. Whitehurst’s base salary to $525,000 from its prior level of $508,725, which represents an approximately 3.2% increase and was based largely on the recommendation of Mr. Warren and the results of the Longnecker study.$475,000.
The 2.5% increase to Messrs. McReynolds, McCrea and Mason reflected a base salary increase consistent with the 2.5% annual merit increase pool set for all employees of ETE and its affiliates for 2017 approved by the respective compensation committees.
Annual Bonus. In addition to base salary, the ETEEnergy Transfer Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Bonus Plan.
The Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Bonus Plan is administered by the Energy Transfer Partners, L.L.C. AnnualCompensation Committee and the Energy Transfer Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan.
For each calendar year or any other period designated by the Energy Transfer Compensation Committee (the “Bonus Plan”“Performance Period”), the Energy Transfer Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). For purposes of the Adjusted EBITDA Target and the DCF Target established in the Bonus Plan, the measures of Adjusted EBITDA and Distributable Cash Flow are calculated using the same definitions as used in the Partnership’s publicly reported financial information, including the Partnership’s earnings press releases, investor presentations, and annual and quarterly filings on Forms 10-K and 10-Q. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.
While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of financial performance objectivesthe Budget Targets during the year for which the bonuses are awardedPerformance Period in light of the contribution of each individual to our profitability and success during such year. The ETEEnergy Transfer Compensation Committee also considers the recommendation of our ChairmanMr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The ETEEnergy Transfer Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.
TheETP Compensation Committee’s evaluation of performanceFor Messrs. McCrea and determination of an overall availableLong, their 2022 bonus pool is based ontargets were 160% of their respective annual base earnings, consistent with their previous 2021 targets. For 2022, therespective internal earnings target generally based on targeted EBITDA (the “Earnings Target”) budget and the performance of each department compared to the applicable departmental budget (with suchperformance measured based on the specific dollar amount of general and administrative expenses set for each department). The two performance criteria are weighted 75% on internal Earnings Target budget criteria and 25% on internal department financialbudget criteria. Internal Earnings Target is the primary performance factor in determining annual bonuses, while internal department financial budget criteria is considered to ensure that the Partnership is effectively managing general and administrative costs in a prudent manner.
For 2017, the ETE Energy Transfer Compensation Committee approved short-term annual cash bonus pool targets for Messrs. McReynolds, Long,Whitehurst, Bramhall and Mason and Whitehurst of 130% of their respective annual base earnings, and aconsistent with their previous 2021 targets. In connection with his promotion to General Counsel Mr. Wright’s bonus pool target of 160% for Mr. McCrea. The 130% target for Mr. Whitehurst represents an increase2022 was increased 130% from his previous targetits prior level of 125% and represents a desire on the part of the Chairman to align the senior officers that report to him, other than Mr. McCrea, with a consistent bonus target. The targets of the other named executive officers were consistent with the prior year’s targets.115%.
In February 2018,2023, the ETPEnergy Transfer Compensation Committee certified 20172022 performance results under the Bonus Plan which resulted in aand authorized payment of 120% of the targeted pool. This bonus payout of 100% of target, which reflected the achievement of 101.6%110% of the internal EarningsAdjusted EBITDA Target, 116% of the DCF Target and 100%94% of, or $47 million under, the Department Budget Target. The Energy Transfer Compensation Committee also used its discretion under the Bonus Plan to exceed the 110% of the budget criteria. achieved pool target
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result and approved a total payout of 120% of the targeted pool amount. The funding of the 120% target was authorized as a result of the significant achievements above the targeted performance metrics.
Based on the approved results, the ETEEnergy Transfer Compensation Committee approved a cash bonus relating to the 20172022 calendar year to Messrs. McReynolds,McCrea, Long, McCrea,Bramhall, Whitehurst, Mason and WhitehurstWright in the amounts of $764,306, $625,100, $1,644,554, $756,958,$2,635,027, $2,635,027, $700,000, $950,000, $1,040,900 and $667,852,$762,540, respectively.

In approving the 2017 bonuses of the named executive officers, the ETE Compensation Committee took into account the achievement by the respective partnerships of all of the targeted performance objectives for 2017 and the individual performances of each of the named executive officers, as well as the study results of Longnecker. The cash bonuses awarded to each of the executive officers for 2017 performance were consistent with their applicable bonus pool targets.
Equity Awards. In 2017, ETE adoptedEnergy Transfer maintains and operates (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”); the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”); (iv) the Amended and Restated Energy Transfer Equity, L.P.LP Long-Term Incentive Plan (the “ETE Plan”“Energy Transfer Plan,” together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “Energy Transfer Incentive Plans”). The ETE Plan authorizesEnergy Transfer Incentive Plans authorize the ETEEnergy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, under each respective plan of restricted units, phantom units, unit options, unit appreciation rights and other awards related to ETE common unitsRSUs upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the ETEEnergy Transfer Incentive Plans. Energy Transfer has generally used time-vested restricted units and/or phantom units as the vehicle for its annual equity awards to eligible employees, including the named executive officers.
In addition, in 2020, Energy Transfer adopted the Energy Transfer LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the Energy Transfer Incentive Plans, awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis, and the CRU Plan is included for purposes of these discussions as an “Energy Transfer Incentive Plan.”
For 2015 and 2016, no2022, the Energy Transfer Compensation Committee established long-term incentive awards were issued undertargets for Messrs. McCrea and Long of 900% of their annual base earnings, consistent with their previous targets. In connection with his promotion to Group Chief Financial Officer effective November 11, 2022, the ETE Plan.Energy Transfer Compensation Committee established the long-term incentive target for Mr. Bramhall of 500% of his annual base earnings, which was an increase from his previous target of 300% of annual base earnings. For 2022, the Energy Transfer Compensation Committee approved long-term incentive targets for Messrs. Whitehurst, Mason and Wright of 500%, 500% and 300%, respectively, of their respective annual base earnings, consistent with their previous targets.
For 2017, theThe annual long-term incentive targets set byare used as the ETE Compensation Committee forbasis to determine the target number of units to be awarded to the eligible participant, including the named executive officers were 500% of annual base salary for Mr. Long, 900% of annual base salary for Mr. McCrea, 500% of annual base salary for Mr. Mason and 400%officers. A multiple of base salary for Mr. Whitehurst, which were consistent withis used to set the pool target, that number is then divided by a weighted average price determined by considering Energy Transfer’s modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior year’s targets.periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are time-vested vehicles. For purposes of establishing an initial price, Energy Transfer utilizes a 60 trading-day trailing weighted average price of Energy Transfer common units prior to November 1, 2022. This average trading price is then subject to adjustment when Energy Transfer’s TUR is more than 5% greater or less than that of its identified peer group. If the TUR analysis yields a result that is within 5% percent of its identified peer group, the Energy Transfer Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the named executive officers. If Energy Transfer’s TUR is outside of the 5% deviation, the 60 trading day trailing weighted average will be adjusted up or down to a maximum of 15% from the trailing weighted average price based on Energy Transfer’s performance as compared to the identified group. For 2022, the peer group included the following:
• Enterprise Products Partners, L.P.• Plains All American Pipeline, L.P.
• The Williams Companies, Inc.• MPLX LP
• Kinder Morgan, Inc.
For 2022, the Partnership’s TUR outperformed the identified peer group by approximately 35% based on the average of the identified comparison periods. Consequently, the 2022 long-term incentive base price was decreased to increase the total available restricted pool by the maximum of 15%.
In December 2017,2022, the ETEEnergy Transfer Compensation Committee in consultation with ETE’s Chairman determined to issue long-term incentive awards under the ETE Plan to the ETE named executive officers, other than Mr. McReynolds, who does not currently receive long-term incentive awards. This determination was made in consideration of limiting the number of units issued under the ETP unit plans for 2017. In December of 2017, the ETE Compensation CommitteeWarren approved grants of phantom unit awardsRSUs to Messrs. McCrea, Long, McCrea,Bramhall, Whitehurst, Mason and WhitehurstWright of 121,074958,950 units, 537,379958,950 units, 135,300175,125 units, 243,750 units, 258,788 units, and 95,945131,250 units, respectively. The Energy Transfer Compensation Committee also approved grants of CRSUs
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to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 319,650 units, 319,650 units, 58,375 units, 81,250 units, 86,262 units and 43,750 units, respectively.
The phantom unit awardsRSUs granted in 2022 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year,year. Vesting of the awards is generally subject to continued employment through each specified vesting date. The phantom unitRSU awards entitle the recipients of the phantom unit awards to receive, with respect to each ETEEnergy Transfer unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by ETEEnergy Transfer to its common unitholders.
The CRSUs granted in 2022 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the award recipient to receive cash equal to the market value of one Energy Transfer common unit upon vesting. The CRSU do not include rights to DER cash payments.
In approving the grant of such phantom unit awards,RSUs and CRSUs, including to the ETEnamed executive officers, the Energy Transfer Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of ETE’s and ETP’sEnergy Transfer’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 20172022 awards would accelerate in the event of the death or disability of the recipient, including the named executive officerofficers, or in the event of a change in control of ETEEnergy Transfer as that term is defined under the ETE Plan.Energy Transfer Incentive Plans.
Upon vestingFor 2020, Mr. McCrea did not receive an award of CRSUs; instead, he received a special one-time time vested cash award of $5,000,000 payable as follows:
•$1,800,000 on December 31, 2020;
•$1,600,000 on July 1, 2021; and
•$1,600,000 on December 5, 2022.
This amount is intended to approximate 50% of Mr. McCrea’s targeted annual equity award and replace the phantom units awarded under the ETE Plan, the ETE Compensation Committee reserves the rightaward of CRSUs made to determine if, upon vesting, such phantom units shall be settled in (i) common units of ETE (subject to the approval of the ETE Plan prior to the first vesting date by a majority of ETE’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ETE Plan) of the ETE common units that would otherwise be delivered pursuant to the terms of eachother named executive officers grant agreement; or (iii) other securities or property (including, without limitation, deliveryofficers. The last payment of common units of ETP purchased by ETE in the open market) in an amount equal to the Fair Market Value of ETE common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ETE Compensation Committee in its discretion.
From time to time, the compensation committees of ETP and/or Sunoco LP may make grants under the respective long-term incentive plans to employees and/or directors containing such terms as the respective compensation committee shall determine. The applicable compensation committee determines the conditions upon which the restricted units or restricted phantom units granted may become vested or forfeited, and whether or not any such restricted units or restricted phantom units will have distribution equivalent rights (“DERs”) entitling the grantee to distributions receive an amount in cash equal to cash distributions$1,600,000 was made by the respective partnership with respect to a like number of partnership common units during the restricted period. For 2017, there were no awards made to the named executive officers under an ETP long-term incentive plan.
In December of 2017, consistent with ETE’s compensation methodology, all of the restricted units and restricted phantom units granted under the long-term incentive plans of ETE, ETP and Sunoco LP, including to the named executive officers, provided for vesting of 60% at the end of the third year and vesting of the remaining 40% at the end of the fifth year, subject to continued employment of the named executive officers through each specified vesting date. The restricted units and restricted phantom unit awards entitle the grantee of the unit awards to receive, with respect to each partnership common unit subject to such restricted unit or restricted phantom unit award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution to the partnership unitholders. In approving the grant of such unit awards, the applicable compensation committee took into account a number of performance factors as well as the long-term objective of retaining such individuals as key drivers of the partnership’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2017 awards would accelerate in the event of the death or disability of the named executive officer or in the event of a change in control of the respective partnership as that term is defined under the applicable long-term incentive plan.

As described below in the section titled Affiliate/Subsidiary Equity Awards, for 2017, in discussions between the General Partner, the ETE Compensation Committees and the compensation committees of the general partners of ETP and Sunoco, it was determined that for 2017 the value of Messrs. Long, Mason and Whitehurst’s awards would be comprised of restricted/phantom unit awards under the ETE Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”) in consideration of their roles and responsibilities for all of the partnerships under ETE’s umbrella and, for Messrs. Long and Mason, as members of the Boards of Directors of the general partner of Sunoco. Messrs. Long, Mason and Whitehurst’s total 2017 long-term awards were allocated 80% to the ETE Plan and 20% to the 2012 Incentive Plan. Mr. McCrea’s 2017 long-term incentive award was allocated entirely to the ETE Plan. It is expected that future long-term incentive awards to the named executive officers of ETE will recognize an aggregation of restricted/phantom restricted units under long-term incentive plans of ETE, ETP and/or Sunoco LP, as applicable.
The ETP and SUN Compensation Committees have in the past and may in the future, but are not required to, accelerate the vesting of unvested restricted unit awards in the event of the termination or retirement of an executive officer. None of the compensation committees accelerated the vesting of restricted unit awards to any ETE named executive officers in 2017.2022.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” certainall outstanding equity awards would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the 2014award agreements for the RSUs and CRSUs awarded in 2020, as well as other awards outstanding held by Partnership employees, including the named executive officers, also include certain acceleration provisions upon retirement with the ability to Messrs. McCreaaccelerate 40% of outstanding unvested awards under the Energy Transfer Incentive Plans at age 65 and Whitehurst included50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section 409(A), which may include a provisionsix (6) month delay in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”. For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.vesting after retirement.
We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control and the acceleration of vesting awards upon a termination without “cause” in the case of the 2014 awards to Messrs. McCrea and Whitehurst creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.
Affiliate and Subsidiary Equity Awards. In addition to their roleshis role as officers of our General Partneran officer for Energy Transfer during 2017, Messrs. Long, McCrea, Mason and Whitehurst in their roles have2022, Mr. Bramhall has certain responsibilities for all of the partnerships under ETE’s umbrella,Sunoco LP, including with respect to Mr. McCrea as member of the Boards of Directors of the general partners of ETP and with respect to Mr. Long, as Chief Financial Officer of ETP and a member of the Board of Directors of the general partner of Sunoco LP.leadership role for certain shared service functions.
The SUNSunoco LP Compensation Committee in December 20172022 approved grantsa grant of units awardsRSUs to Messrs. Long, Mason and WhitehurstMr. Bramhall of 17,097, 19,106 and 13,54814,200 restricted units, respectively under the 2012 Incentive Plan related to2018 Sunoco LP common units.Plan. The terms and conditions of the restricted unit/phantom awardsunit to Messrs. Long, Mason and WhitehurstMr. Bramhall under the 2012 Incentive2018 Sunoco LP Plan as applicable, were the same and provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awardsaward would be accelerated in the event of theirhis death or disability, or upon a change in control. The retirement acceleration provisions for this award under the 2018 Sunoco LP Plan are the same as the retirement acceleration provisions under Energy Transfer Incentive Plans with the ability to accelerate at retirement 40% of outstanding unvested awards at age 65 and 50% at age 68.
Special One-Time Awards to Co-Chief Executive Officers. In recognition of their assumption of their new roles as Co-Chief Executive Officers effective January 1, 2021, the Energy Transfer Compensation Committee approved certain one-time awards to Messrs. McCrea and Long.
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Mr. McCrea received a special one-time award of 241,815 RSUs under the Energy Transfer Incentive Plans and a special cash payment of $1,625,000 in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
Mr. Long received a special one-time award of 483,630 RSUs under the Energy Transfer Incentive Plans in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
The RSU awards to Messrs. McCrea and Long were made at the same grant date valuation and vesting schedules used for the annual equity awards described above under “—Equity Awards” section above. These awards were approved by the Energy Transfer Compensation Committee on December 30, 2020 to be effective immediately upon Messrs. McCrea and Long assuming their new roles on January 1, 2021 and are reflected as compensation in 2021 in the Compensation Tables section below.
Unit Ownership Guidelines. In December 2013,2021, the Board of Directors of our General Partner adopted an update to the Executive Unit Ownership Guidelines (the “Guidelines”), which setsets forth minimum ownership guidelines applicable to certain executives of ETE and ETPEnergy Transfer with respect to ETE, ETPEnergy Transfer and Sunoco LP common units, representing limited partnership interests, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, Mr. McReynolds as ETE’s President and Mr. McCrea as Group(i) the Chief Operations Officer and Chief Commercial OfficerExecutive Officer/Co-Chief Executive Officer(s) are expected to own common units having a minimum value of fivesix times their base salariessalary; (ii) the Chief Operating Officer, the Chief Financial Officer, the General Counsel and Messrs. Long, Mason and Whitehurst areother C-Suite executives expected to own common units having a minimum value of four times their respective base salaries.salary; and (iii) Senior Vice Presidents are expected to own common units having a minimum value of two times their respective base salary. In addition to the named executive officers, thethese Guidelines also apply to other covered executives, all of whomwhich executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from twoone to four times their respective base salaries.salary.
The ETEEnergy Transfer Compensation Committee believes that the ownership of ETE, ETPEnergy Transfer and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ETE’sEnergy Transfer’s total unitholder return,

aligning the interests of such executives with those of ETE’s Unitholders, and promoting ETE’sEnergy Transfer’s interest in good corporate governance.
Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines; however, certain covered executives, based on their tenure as an executive, are required to achieve compliance within two yearsGuidelines. As of December 31, 2022, all of the December 2013 effective datenamed executive officers were compliant with the level required of the Guidelines. Thus, compliance with the Guidelines was required for Messrs. McReynolds, McCrea and Mason beginning in December 2015, and they were compliant. Compliance for Mr. Long will be required in December 2018, and compliance for Mr. Whitehurst will be required in December 2019.as of that date.
Covered executives may satisfy the Guidelines through direct ownership of ETE, ETPEnergy Transfer and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of ETE, ETPEnergy Transfer and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.
Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.
The Board of Directors of ETP’s general partner approved and adopted policies substantially identical to the Guidelines described above.
Qualified Retirement Plan Benefits. The Energy Transfer Partners GP, L.P.LP 401(k) Plan (the “ETP“Energy Transfer 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. During 2020, in response to challenging conditions within the industry, including impacts of the COVID-19 pandemic, Energy Transfer suspended its 401(k) matching contribution from July 1, 2020 through December 31, 2020. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.
The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service. As with the 401(k) matching contributions, Energy Transfer suspended the profit
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sharing contribution from July 1, 2020 through December 31, 2020; however, the profit sharing contributions were reinstated for the full year 2021 and continued throughout 2022.
Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in ETP GP’sthe Partnership’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.
Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner. In addition, ETEPartner; however, the award agreement to the named executive officers under the Energy Transfer Incentive Plans, the 2018 Sunoco LP Plan Second Amended and Restated Energy Transfers Partners, L.P. 2008the Sunoco LP 2012 Long-Term Incentive Plan (the “2008 Incentive“2012 Sunoco LP Plan”), the Energy Transfer Partners, L.P. Amended and Restated 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”), and the Energy Transfer Partners, L.L.C. Long Term Incentive Plan, as amended and restated (the “ETP Plan”) provide the ETP Compensation Committee with the discretion, unless otherwise specified in the applicable award agreement, to provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. In the case of the December 2014 and 2015 long-term incentive awards to the named executive officers under ETP’s 2008 Incentive Plan, the ETP Plan or the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”), the awards would immediately and fully vest all unvested restricted unit awards in the event of a change of control, as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional information.
In addition, ETP GPin 2021 the Partnership has also adopted the ETP GPPartnership Severance Plan and Summary Plan Description effective as of June 12, 2013,December 1, 2021, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried

employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.
ETPEnergy Transfer LP Non-Qualified Deferred Compensation Plan (the “ETP“Energy Transfer NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ETPEnergy Transfer NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the ETPEnergy Transfer NQDC Plan, ETPEnergy Transfer may make annual discretionary matching contributions to participants’ accounts; however, ETPEnergy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the ETPEnergy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the ETPEnergy Transfer NQDC Plan) of ETP,Energy Transfer, all ETPEnergy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the ETPEnergy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement. None of our named executive officers currently participate in this plan.
Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of our unitholdersUnitholders and our subsidiaries’ unitholders for our long-term performance.
145
Tax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation
We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes.
Accounting for Unit-BasedNon-Cash Compensation
For unit-basednon-cash compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 2 and Note 9 to our consolidated financial statements.
Compensation Committee Interlocks and Insider Participation
Mr. TurnerSteven R. Anderson and Mr. Richard D. BrannonMichael K. Grimm are the only members of the Energy Transfer Compensation Committee. Mr. Ray W. Washburne also served as a member of the Compensation Committee prior to his resignation from the board of directors of our General Partner effective April 1, 2022. During 2017,2022, no member of the Energy Transfer Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neitherNeither Mr. TurnerGrimm nor Mr. Richard D. BrannonWashburne is a former employee of ours or any of our subsidiaries.


Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009, as discussed in his biographical information included in “Item 10. Directors, Executive Officers and Corporate Governance.”
Report of Compensation Committee
The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of ETE.Energy Transfer. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.


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


Steven R. Anderson
Michael K. Rick Turner
Richard D. BrannonGrimm
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act, of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.
146
Compensation Tables
Summary Compensation Table
Name and Principal PositionYearSalary
($)		Bonus
($)
Equity
Awards (1)
($)
Non-Equity
Incentive Plan
Compensation(2)
($)
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
All Other
Compensation (3)
($)
Total
($)
Thomas E. Long2022$1,372,410 $— $14,344,161 $2,635,027 $— $23,917 $18,375,515 
Co-Chief Executive Officer20211,322,750 — 15,224,039 3,156,400 — 27,014 19,730,203 
2020623,077 — 2,781,255 — — 21,603 3,425,935 
Marshall S. (Mackie) McCrea, III (4)
20221,372,410 1,600,000 14,344,161 2,635,027 — 22,794 19,974,392 
Co-Chief Executive Officer20211,322,750 3,225,000 13,734,458 3,156,400 — 22,044 21,460,652 
20201,157,423 1,800,000 4,597,516 — — 18,045 7,572,984 
Dylan A. Bramhall2022429,808 — 3,241,514 700,000 — 16,298 4,387,620 
Group Chief Financial Officer
Bradford D. Whitehurst2022628,125 — 3,646,060 950,000 — 18,510 5,242,695 
Executive Vice President – Tax and Corporate Initiatives2021605,413 — 3,102,694 1,174,000 — 15,760 4,897,867 
2020581,202 — 2,596,850 — — 16,224 3,194,276 
Thomas P. Mason2022666,595 — 3,870,995 1,040,900 21,917 5,600,407 
Executive Vice President – Alternative Energy and President – LNG2021642,445 — 3,279,498 1,252,000 — 22,706 5,196,649 
2020655,680 — 2,609,350 — — 20,007 3,285,037 
James M. Wright, Jr.2022488,808 — 1,963,263 762,540 18,550 19,120 3,252,281 
Executive Vice President, General Counsel and Chief Compliance Officer
Name and Principal Position Year 
Salary
($)
 
Bonus (1)
($)
 
Equity
Awards (2)
($)
 
Option
Awards
($)
 
Non-Equity
Incentive Plan
Compensation
($)
 
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
 
All Other
Compensation (3)
($)
 
Total
($)
ETE Officers:                  
John W. McReynolds 2017 $587,928
 $764,306
 $—
 $—
 $—
 $—
 $15,179
 $1,367,413
President 2016 577,280
 712,922
 —
 —
 —
 —
 10,768
 1,300,970
 2015 560,154
 700,893
 —
 —
 —
 —
 11,103
 1,272,150
Thomas E. Long 2017 480,846
 625,100
 2,519,954
 —
 —
 —
 18,320
 3,644,220
Group Chief Financial Officer 2016 454,154
 560,865
 2,007,697
 —
 —
 —
 14,679
 3,037,395
 2015 399,207
 480,296
 1,447,063
 —
 —
 —
 14,282
 2,340,848
Marshall S. (Mackie) McCrea, III 2017 1,027,846
 1,644,554
 9,033,341
 —
 —
 —
 16,834
 11,722,575
Group Chief Operating Officer and Chief Commercial Officer 2016 1,009,231
 1,533,990
 8,059,413
 —
 —
 —
 14,818
 10,617,452
 2015 840,385
 1,294,192
 6,646,354
 —
 —
 —
 14,282
 8,795,213
Thomas P. Mason 2017 582,275
 756,958
 2,816,048
       18,618
 4,173,899
Executive Vice President and General Counsel 2016 571,729
 706,067
 2,524,064
       14,818
 3,816,678
 2015 557,615
 6,300,000
 2,253,927
 —
 —
 —
 14,282
 9,125,824
Brad Whitehurst 2017 513,733
 667,852
 1,996,921
       14,275
 3,192,781
Executive Vice President and Head of Tax 2016 503,354
 597,717
 1,777,758
       14,816
 2,893,645
 2015 485,962
 584,673
 1,587,514
 —
 —
 —
 37,947
 2,696,096
(1)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. For Messrs. Long, Bramhall and Whitehurst amounts for one or more periods include equity awards of our subsidiary, Sunoco LP, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. Although the CRSU awards may only be settled in cash, they are based upon the value of Energy Transfer common units and are accounted for as equity awards within these compensation tables.
(1)
The discretionary cash bonus amounts earned named executive officers for 2017 reflect cash bonuses approved by the ETE and ETP Compensation Committees in February 2018 that are expected to be paid on or before March 15, 2018.
(2)
Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.
(3)
The amounts reflected for 2017 in this column include (i) matching contributions to the ETP 401(k) Plan made on behalf of the named executive officers of $9,024 for Mr. McReynolds and $13,500 for each Messrs. Long, McCrea, Mason and Whitehurst, respectively,
(2)Energy Transfer maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis.
(3)The amounts reflected for 2022 in this column include (i) matching contributions to the Energy Transfer 401(k) Plan made on behalf of the named executive officers of $15,250 each for Messrs. Long, McCrea, Bramhall, Whitehurst, Mason and Wright, and (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long, McCrea, Whitehurst and Wright, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Unit Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent

rights were originally granted. For 2017,2022, distribution payments in connection with distribution equivalent rights totaled $423,809$2,072,643 for Mr. Long, $1,928,181$2,826,685 for Mr. McCrea, $680,261$340,120 for Mr. Bramhall, $798,532 for Mr. Whitehurst, $791,164 for Mr. Mason, and $526,388$334,890 for Mr. Whitehurst.Wright; these amounts include distribution payments on Sunoco LP unit awards for those executives with such unvested awards.
(4)The amounts reflected in the bonus column for Mr. McCrea includes the second payment of Mr. McCrea’s time-vested cash award, which award represented 50% of Mr. McCrea’s total equity award target in 2020. These bonus amounts were paid as follows: $1,800,000 on December 31, 2020, $1,600,000 on July 1, 2021 and $1,600,000 on December 5, 2022. For 2021, the bonus amount reflected above also includes the vesting and payment on February 1, 2021 of a one-time, time-vested cash award of $1,625,000 to Mr. McCrea, which was originally granted in October 2020 in connection with Mr. McCrea’s assumption of his role as Co-Chief Executive Officer.
147
Grants of Plan-Based Awards Tablein 2022
NameGrant DateAll Other Unit Awards: Number of Units
(#)
Grant Date Fair Value of Unit Awards (1)
Energy Transfer Unit Awards:
Thomas E. Long12/12/2022958,950 $11,219,715 
Marshal S. (Mackie) McCrea, III12/12/2022958,950 11,219,715 
Dylan A. Bramhall12/12/2022175,125 2,048,963 
Bradford D. Whitehurst12/12/2022243,750 2,851,875 
Thomas P. Mason12/12/2022258,788 3,027,820 
James M. Wright, Jr.12/12/2022131,250 1,535,625 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long12/12/2022319,650 3,124,446 
Marshal S. (Mackie) McCrea, III12/12/2022319,650 3,124,446 
Dylan A. Bramhall12/12/202258,375 570,591 
Bradford D. Whitehurst12/12/202281,250 794,185 
Thomas P. Mason12/12/202286,262 843,175 
James M. Wright, Jr.12/12/202243,750 427,638 
Sunoco LP Unit Awards:
Dylan A. Bramhall12/12/202214,200 621,960 
(1)We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
148
Name Grant Date 
All Other Unit Awards: Number of Units
(#)
 
All Other Option Awards: Number of Securities Underlying Options
(#)
 
Exercise or Base Price of Option Awards
($ / Unit)
 
Grant Date Fair Value of Unit Awards (1)
ETE Unit Awards:          
Thomas E. Long 12/20/2017 121,074
 —
 $—
 $2,035,254
Marshal S. (Mackie) McCrea, III 12/20/2017 537,379
 —
 —
 9,033,341
Thomas P. Mason 12/20/2017 135,300
 —
 —
 2,274,393
Bradford D. Whitehurst 12/20/2017 95,945
 —
 —
 1,612,835
Sunoco LP Unit Awards:          
Thomas E. Long 12/21/2017 17,097
 —
 —
 484,700
Thomas P. Mason 12/21/2017 19,106
 —
 —
 541,655
Bradford D. Whitehurst 12/21/2017 13,548
 —
 —
 384,086
(1)
We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements.
Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, nonqualified deferred compensation earnings (and losses), and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.

Outstanding Equity Awards at 20172022 Fiscal Year-End Table
Name
Grant Date(1)
Unit Awards (1)
Number of Units That Have Not Vested(2)
(#)
Market or Payout Value of Units That Have Not Vested (3)
($)
Energy Transfer Unit Awards:
Thomas E. Long12/12/2022958,950 $11,382,737 
12/16/20211,121,250 13,309,238 
12/30/2020662,180 7,860,077 
12/16/201986,000 1,020,820 
12/18/201854,590 647,983 
10/19/201846,080 546,970 
Marshal S. (Mackie) McCrea, III12/12/2022958,950 11,382,737 
12/16/20211,121,250 13,309,238 
12/30/2020988,165 11,729,519 
12/16/2019272,960 3,240,035 
12/18/2018242,296 2,876,054 
Dylan A. Bramhall12/12/2022175,125 2,078,734 
12/16/202183,400 989,958 
12/30/202037,500 445,125 
12/16/201921,000 249,270 
12/18/201818,000 213,660 
Bradford D. Whitehurst12/12/2022243,750 2,893,313 
12/16/2021228,000 2,706,360 
12/30/2020166,600 1,977,542 
12/16/201960,920 723,120 
12/18/201854,076 641,882 
Thomas P. Mason12/12/2022258,788 3,071,814 
12/16/2021300,300 3,564,561 
12/30/2020234,900 2,788,263 
12/16/201985,920 1,019,870 
12/18/201876,256 905,159 
James M. Wright, Jr.12/12/2022131,250 1,557,938 
12/16/2021131,944 1,566,175 
12/30/202098,755 1,172,222 
12/16/201936,120 428,744 
12/18/201832,060 380,552 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long12/12/2022319,650 3,179,882 
12/16/2021249,167 2,589,238 
12/30/202059,517 646,228 
Marshal S. (Mackie) McCrea, III12/12/2022319,650 3,179,882 
12/16/2021249,167 2,589,241 
Dylan A. Bramhall12/12/202258,375 580,715 
12/16/202118,534 192,598 
12/30/202012,500 135,723 
Bradford D. Whitehurst12/12/202281,250 808,276 
12/16/202150,667 526,511 
12/30/202055,534 602,981 
149
Name 
Grant Date
(2)
 
Unit Awards (1)
Number of Units That Have Not Vested
(#)
 
Market or Payout Value of Units That Have Not Vested
($) (3)
ETE Unit Awards:    
Thomas E. Long 12/20/2017 121,074
 2,089,737
Marshal S. (Mackie) McCrea, III 12/20/2017 537,379
 9,275,162
Thomas P. Mason 12/20/2017 135,300
 2,335,278
Bradford D. Whitehurst 12/20/2017 95,945
 1,656,011
ETP Unit Awards:    
Thomas E. Long 12/29/2016 59,053
 1,058,229
 12/9/2015 27,788
 497,952
 12/4/2015 11,208
 200,847
 12/16/2014 8,192
 146,792
 12/5/2013 6,516
 116,767
    
Marshal S. (Mackie) McCrea, III 12/29/2016 336,386
 6,028,028
 12/9/2015 185,261
 3,319,868
 12/4/2015 93,390
 1,673,549
 12/16/2014 37,590
 673,613
 12/5/2014 16,454
 294,863
 12/30/2013 41,625
 745,920
 12/3/2013 21,840
 391,373
Thomas P. Mason 12/29/2016 79,384
 1,422,552
Thomas P. Mason12/12/202286,262 858,135 
 12/9/2015 43,733
 783,686
12/16/202166,734 693,472 
 12/4/2015 22,046
 395,064
12/30/202078,300 850,172 
James M. Wright, Jr.James M. Wright, Jr.12/12/202243,750 435,226 
12/16/202129,321 304,692 
12/30/202032,919 357,427 
Sunoco LP Unit Awards:Sunoco LP Unit Awards:
Thomas E. LongThomas E. Long12/30/202027,800 1,198,180 
12/16/20197,800 336,180 
12/19/20187,730 333,163 
Dylan A. BramhallDylan A. Bramhall12/12/202214,200 612,020 
 12/16/2014 12,963
 232,297
12/16/202113,000 560,300 
 12/5/2014 6,047
 108,362
12/30/202016,000 689,600 
 12/30/2013 24,554
 440,004
10/27/202020,000 862,000 
Bradford D. Whitehurst 12/29/2016 55,913
 1,001,952
Bradford D. Whitehurst12/16/202116,100 693,910 
 12/9/2015 30,803
 551,981
12/30/202026,000 1,120,600 
 12/4/2015 15,528
 278,262
12/16/20197,280 313,768 
 12/16/2014 11,138
 199,584
12/19/20187,658 330,060 
 12/5/2014 5,224
 93,614
 8/1/2014 26,995
 483,751
 12/30/2013 16,922
 303,239
Sunoco LP Unit Awards:    
Thomas E. Long 12/21/2017 17,097
 485,555
 12/29/2016 22,210
 630,764
 12/16/2015 14,125
 401,150
Thomas P. Mason 12/21/2017 19,106
 542,610
 12/29/2016 23,300
 661,720
 12/16/2015 18,523
 526,053
Bradford D. Whitehurst 12/21/2017 13,548
 384,763
 12/29/2016 16,410
 466,044
 12/16/2015 13,046
 370,506
James M. Wright, Jr.James M. Wright, Jr.12/19/201832,060 1,381,786 
(1)
In connection with the April 28, 2017 merger between ETP and Sunoco Logistics, each outstanding unvested ETP restricted unit converted into 1.5
(1)Certain of these outstanding awards represent subsidiary awards that converted into Energy Transfer awards upon the in connection with restructuring transactions in prior periods.
(2)Energy Transfer and Sunoco LP unit awards outstanding vest as follows:
•at a rate of 60% in December 2025 and 40% in December 2027 for awards granted in December 2022;
•at a rate of 60% in December 2024 and 40% in December 2026 for awards granted in December 2021;
•at a rate of 60% in December 2023 and 40% in December 2025 for awards granted in December 2020;
•100% in December 2024 for the remaining outstanding portion of awards granted in December 2019; and
•100% in December 2023 for the remaining outstanding portion of awards granted in October and December 2018.
Such awards may be settledat the election of the Energy Transfer Compensation Committee in (i) common units of Sunoco Logistics, maintaining the same terms as the original ETP award. In connection with the merger, Sunoco Logistics changed its name to Energy Transfer Partners, L.P. Certain of these outstanding awards represent ETP awards that converted into Sunoco Logistics awards in connection with the merger.
(2)
ETE phantom unit awards outstanding vest at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017. Such awards may be settledat the election of the ETE Compensation Committee in (i) common units of

ETE (subject to the approval of the ETE PlanEnergy Transfer Incentive Plans prior to the first vesting date by a majority of ETE’s unitholdersUnitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ETE Plan)Energy Transfer Incentive Plans) of the ETEEnergy Transfer common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property (including, without limitation, delivery of common units of ETP purchased by ETE in the open market) in an amount equal to the Fair Market Value of ETEEnergy Transfer common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ETEEnergy Transfer Compensation Committee in its discretion.
ETP and Sunoco LP commonEnergy Transfer cash restricted unit awards outstanding vest as follows:
at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;
at a rate of 60%2022 vest 1/3 per year in December 20182023, 2024 and 40% in December 2020 for2025. Energy Transfer cash restricted unit awards granted in December 2015;
100%2021 vest 1/2 per year in December 2019 for the2023 and 2024. The remaining outstanding portion ofEnergy Transfer cash restricted unit awards granted in December 2014; and
100%2020 vest in December 20182023.
(3)Market value was computed as the number of unvested awards as of December 31, 2022 multiplied by the closing price of respective common units of Energy Transfer and Sunoco LP. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the remaining outstanding portionexpected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
150
(3)
Market value was computed as the number of unvested awards as of December 31, 2017 multiplied by the closing price of respective common units of ETE, ETP and Sunoco LP.
Option Exercises and Units Vested Tablein 2022
Unit Awards
NameNumber of Units
Acquired on Vesting
(#)
Value Realized on Vesting
($) (1)
Energy Transfer Unit Awards:
Thomas E. Long177,430 $2,161,097 
Marshall S. (Mackie) McCrea, III624,392 7,605,095 
Dylan A. Bramhall31,500 383,670 
Bradford D. Whitehurst129,758 1,580,452 
Thomas P. Mason183,000 2,228,940 
James M. Wright, Jr.54,180 659,912 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long184,100 2,242,342 
Marshall S. (Mackie) McCrea, III124,583 1,517,421 
Dylan A. Bramhall21,766 265,110 
Bradford D. Whitehurst80,866 984,948 
Thomas P. Mason111,666 1,360,092 
James M. Wright, Jr.47,578 579,500 
Sunoco LP Unit Awards:
Thomas E. Long18,539 812,008 
Bradford D. Whitehurst16,340 715,692 
Thomas P. Mason7,643 334,763 
  Unit Awards
Name 
Number of Units
Acquired on Vesting
(#)
 
Value Realized on Vesting
($) (1)
ETP Unit Awards:    
Thomas E. Long 18,471
 301,576
Marshall S. (Mackie) McCrea, III 107,732
 1,758,957
Thomas P. Mason 46,513
 759,418
Bradford D. Whitehurst 24,540
 400,665
(1)Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date.
(1)
Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of common units for ETP upon the vesting date.
We have not issued option awards.
Nonqualified Deferred Compensation Table
A description of the key provisions of the Partnership’s non-qualified deferred compensation plan can be found in the compensation discussion and analysis above. None
NameExecutive Contributions in Last FY ($)
Acquired on Vesting
(#)
Registrant Contributions in Last FY ($)
($) (1)
Aggregate Earnings in Last FY ($) (1)
Aggregate Withdrawals/Distributions ($)Aggregate Balance at Last FYE ($)
James M. Wright, Jr.— — 18,550 — 69,745 
(1)Amounts included in the aggregate earnings column above have been included in the change in non-qualified deferred compensation earnings column of the named executive officers participated in the plan in 2017.summary compensation table.
Potential Payments Upon a Termination or Change of Control
Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards (including cash restricted unit awards) granted pursuant the ETE PlanEnergy Transfer Incentive Plans will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of ETEEnergy Transfer or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of ETE;Energy Transfer; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of ETEEnergy Transfer in one or more transactions to anyone other than an affiliate of ETE.Energy Transfer.
In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards, phantom unit awards and cash restricted unit awards under the equity incentive plans of ETEEnergy Transfer Incentive Plans, the Sunoco LP Plan and its affiliated partnerships,the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards granted in 2015, 2016 and 2017outstanding to the named executive officers under the ETEEnergy Transfer
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Incentive Plans, the 2018 Sunoco LP Plan the 2008 Incentive Plan, the 2011 Incentive Plan, the ETP Plan andor the 2012 IncentiveSunoco LP Plan would be accelerated in the event of a change in control of the Partnership.
The 2014 awardsOctober 2018 equity award to Messrs. McCrea and Whitehurst, whether awarded under the 2008 Incentive Plan, the 2011 Incentive Plan or the Sunoco Logistic PlanMr. Long included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea

as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.
In addition, the ETEEnergy Transfer Compensation Committee the ETP Compensation Committees and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least tenfive years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The Sunoco Logistics Compensation Committee beginning with awards made in December 2014 have included a provision in the award agreement which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A).
With respect to Mr. Mason, Beginning with awards granted in February 2016,2022, the ETE Compensation Committee approved a one-time special incentive retention bonus inretirement provision also requires that the amount of $6,300,000 (the “Special Bonus”).  The Special Bonus was approved by the ETE Compensation Committee based on a recommendation of ETE senior management in recognition of, among other things, (i) Mr. Mason’s appointment as the Executive Vice President and General Counsel of the General Partner; (ii) his 2015 calendaraward be held for at least one year performance; and (iii) his contributions to ETE and its family of partnerships on several key initiatives, including (a) the drop-down transactions by and between ETP and Sunoco LP, (b) the proposed merger transaction between the ETE and The Williams Companies, Inc., (c) the liquefied natural gas (LNG) export project of ETE, and (d) the simplification of the overall Energy Transfer family structure.  The approval of the Special Bonus by the ETE Compensation Committee was conditioned upon entry by Mr. Mason into a Retention Agreement with ETE (the “Retention Agreement”) which provides (i) if, prior to the third (3rd) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay one-hundred percent (100%) of the Special Bonus to ETE; (ii) if, after the third (3rd) anniversary but priorgrant date in order to the fourth (4th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Masonbe eligible for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay seventy-five percent (75%) of the Special Bonus to ETE; and (iii) if, after the fourth (4th) anniversary but prior to the fifth (5th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay fifty percent (50%) of the Special Bonus to ETE.  Mr. Mason and ETE entered into the Retention Agreement on February 24, 2016.acceleration.
Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the ETPEnergy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the ETPEnergy Transfer NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the ETPEnergy Transfer NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).
CEO Pay Ratio
In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. McReynolds, our PresidentMessrs. Long and McCrea, Co-Chief Executive Officers, and the annual total compensation of our employees. We are using Mr. McReynolds for purposes of the CEO pay ratio as ETE does not have an elected Chief Executive Officer and Mr. McReynolds serves as ETE’s principal executive officer. Mr. Kelcy Warren serves as ETE’s Chairman and the Chairman and Chief Executive Officer of ETP. Additionally, for purposes of this disclosure we used the same data used for the ETP CEO pay ratio as the employee base supporting ETP is substantially the same employee base supporting ETE.
For the 20172022 calendar year:
Theyear, the annual total compensation of Mr. McReynolds,Messrs. Long and McCrea, as reported in the Summary Compensation TablesTable of this Item 11was $1,367,413;11 was $18,375,515 and

$19,974,392, respectively.
The median total compensation of the employees supporting ETPthe Partnership (other than Mr. Warren)Messrs. Long and McCrea) was $115,226.$132,358 for 2022, which amount was updated from the 2021 “median employee.”
Based on this information, for 20172022 the rationratio of the annual total compensation of Mr. McReynoldsMessrs. Long and McCrea to the median of the annual total compensation of the 8,494 employees supporting ETP, which is substantially the same employee base supporting ETE,Partnership as of December 31, 20172022 was approximately 12139 to 1.1 and 151 to 1, respectively.
To identify the median of the annual total compensation of the employees supporting ETE and ETP,the Partnership, the following steps were taken:
1.It was determined that, as of December 31, 2017, the applicable employee populations consisted of 8,494 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2017 that are required to be included in our employee population for the CEO pay ratio evaluation.
2.To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2017.
3.We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”
4.Once we identified our median employee, we combined all elements of the employee’s compensation for 2017 resulting in an annual compensation of $115,226. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $10,800) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $5,846 per employee, includes $3,633 per employee on average matching contribution and $2,213 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).
5.With respect to Mr. McReynolds, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table under this Item 11.
1.It was determined that, as of December 31, 2022, the applicable employee populations consisted of 9,533 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2022 that are required to be included in our employee population for the CEO pay ratio evaluation.
2.To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2021, and for 2022, updated the compensation of the “median employee” as reflected in our payroll records as reported on form W-2 for 2022.
3.We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”
4.Once we identified our median employee, we combined all elements of the employee’s compensation for 2022 resulting in an annual compensation of $132,358 with total base salary of $113,189 The difference between such employee’s total
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earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $12,827) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $6,342 per employee, includes $4,097 per employee on average matching contribution and $2,245 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).
5.With respect to Messrs. Long and McCrea, we used the amount reported in the “Total” column of our 2022 Summary Compensation Table under this Item 11.
Director Compensation
Directors of our General Partner, who are employees of the ETP GP or any of their subsidiaries, are not eligible for director compensation. In 2017,2022, the compensation arrangements for outside directors included a $50,000$100,000 annual retainer for services on the board. If a director served on the ETEEnergy Transfer Audit Committee, such director would receive an annual cash retainer ($10,00015,000 or $15,000$25,000 in the case of the chairman) and meeting attendance fees ($1,200). If a director served on the ETEEnergy Transfer Compensation Committee, such director would receive an annual cash retainer ($5,0007,500 or $7,500$15,000 in the case of the chairman) and meeting attendance. The fees ($1,200).for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment.
The outside directors of our General Partner are also entitled to an annual restricted unit award under the ETE PlanEnergy Transfer Incentive Plans equal to an aggregate of $100,000 divided by the closing price of ETEEnergy Transfer common units on the date of grant. These ETEEnergy Transfer common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the ETEEnergy Transfer common units and is recognized over the vesting period. Distributions are paid during the vesting period.

The compensation paid to the non-employee directors of our General Partner in 20172022 is reflected in the following table:
Name
Fees Paid in Cash(1)
($)
Unit Awards(2)
($)
All Other Compensation
($)		Total
($)
Steven R. Anderson$122,500 $100,000 $— $222,500 
Richard D. Brannon125,000 100,000 — 225,000 
Ray C. Davis (3)
100,000 100,000 — 200,000 
Michael K. Grimm130,000 100,000 — 230,000 
James R. Perry100,000 100,000 — 200,000 
Ray W. Washburne (4)
53,750 100,000 — 153,750 
Name 
Fees Paid in Cash(1)
($)
 
Unit Awards(2)
($)
 
All Other Compensation
($)
 
Total
($)
Richard D. Brannon        
As ETE director $83,965
 $99,991
 $—
 $183,956
K. Rick Turner 

 

   
As ETE director 80,700
 99,991
 —
 180,691
As Sunoco LP Director 82,100
 100,008
 —
 182,108
William P. Williams 

     
As ETE director 74,600
 99,991
 —
 174,591
As Sunoco LP Director     —
 —
(1)Fees paid in cash are based on amounts paid during the period.
(1)
(2)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.
(3)Mr. Davis resigned from the board of directors of our General Partner, effective December 31, 2022.
(4)Mr. Washburne resigned from the board of directors of our General Partner, effective April 1, 2022.
Fees paid in cash are based on amounts paid during the period.
(2)
Unit award amounts reflect the aggregate grant date fair value of awards granted based on the market price of ETE common units, ETP common units or Sunoco LP Common Units, accordingly, as of the grant date.
As of December 31, 2017,2022, Mr. BrannonAnderson had 7,71639,390 unvested ETEEnergy Transfer restricted units outstanding, Mr. TurnerBrannon had 20,42340,645 unvested ETEEnergy Transfer restricted units outstanding, Mr. Davis had 39,390 unvested Energy Transfer restricted units outstanding, Mr. Grimm had 47,415 unvested Energy Transfer restricted units outstanding and Mr. WilliamsPerry had 15,739 ETE43,868 unvested Energy Transfer restricted units outstanding.
For 2018,Non-independent directors do not receive compensation for their service on the Board of our General Partner has approved modifications to the compensation of non-employee directorsboard of our General Partner. TheNon-independent directors will receive an annual retainer fee of $100,000 in cash up from $50,000 in 2017. In addition,include the Chairman of the Audit Committee will receive an annual fee of $25,000 up from $15,000 in 2017executive chairman and the membersemployee directors, as well as Messrs. McReynolds and Ramsey, both of whom recently retired from the Audit Committee will receive an annual feePartnership. In connection with his retirement, as previously reported by the Partnership, Mr. Ramsey received accelerated vesting of $15,000 up from $10,000.certain equity awards granted during his employment. The Chairmanvesting of our Compensation Committee will receive an annual fee of $15,000 up from 7,500those equity awards was determined in 2017connection with Mr. Ramsey’s employment and the members of our Compensation Committee will receive an annual fee of $7,500 up from $5,000 in 2017. The fees for membershipretirement, not his service on the Conflicts Committeeboard; therefore, no compensation is reflected in the table above for such vesting.
For 2023, the Board has adopted new compensation arrangement for outside directors, which will continue to be determined on a per instance basis for each Conflicts Committee assignment.
Additionally for 2018,raise the value of equity awards issued toannual restricted unit award under the non-employee directors will remainEnergy Transfer Incentive Plans equal to an aggregate of $100,000$125,000. The awards using the same grant date valuation as is used for annual long-term incentive awards made to Partnership officers, including the named executive officers, through the annual modified total unitholder return analysis. Additionally, moving forward awards to outside directors will be divided bymade at the closing pricesame time such awards are made to the Partnership officers, usually in December of our Common Units on the dateeach year.
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The proposed compensation changes for the non-employee directors for 2018 were developed in consultation with Mr. Warren after considering the results of a review of directors’ compensation by Longnecker during 2017.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Equity Compensation Plan Information
At the time of our initial public offering, we adopted the Energy Transfer Equity, L.P. Long-Term Incentive Plan for the employees, directors and consultants of our General Partner and its affiliates who perform services for us. The long-term incentive plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The long-term incentive plan limits the number of units that may be delivered pursuant to awards to three million units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan is administered by the compensation committee of the board of directors of our General Partner.

The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2017:2022:
Plan Category 
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)
 
Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
 
Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
Plan CategoryNumber of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)		Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)		Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
Equity compensation plans approved by security holders —
 $—
 —
Equity compensation plans approved by security holders— $— — 
Equity compensation plans not approved by security holders:      
Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan 1,198,239
 —
 10,752,488
Equity compensation plans not approved by security holdersEquity compensation plans not approved by security holders37,713,968 — 3,578,984 
Total 1,198,239
 $—
 10,752,488
Total37,713,968 $— 3,578,984 
Energy Transfer Equity, L.P.LP Units
The following table sets forth certain information as of February 16, 2018,10, 2023, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.
Beneficially Owned (2)
Percent of Class
Name and Address of
Beneficial Owner (1)
Common Units
Class A
Units(3)
Common UnitsClass A Units
Kelcy L. Warren (4)
287,799,984 765,993,4299.3 %100.0 %
Thomas E. Long773,628 — *N/A
Marshall S. (Mackie) McCrea, III3,085,646 — *N/A
Dylan A. Bramhall109,943 — *N/A
Thomas P. Mason744,056 — *N/A
Bradford D. Whitehurst (5)
538,709 — *N/A
James M. Wright, Jr.221,266 — *N/A
Steven R. Anderson (6)
1,555,163 — *N/A
Richard D. Brannon (7)
696,071 — *N/A
Michael K. Grimm (8)
688,941 — *N/A
John W. McReynolds (9)
30,225,200 — *N/A
James R. Perry126,027 — *N/A
Matthew S. Ramsey1,121,845 — *N/A
Blackstone Holdings I/II GP L.L.C. (10)
160,737,127 — 5.2 %N/A
All Directors and Executive Officers as a group (14 persons)327,802,291 765,993,429 10.6 %100.0 %
*    Less than 1%
(1)The address for all listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.
(2)Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power
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Name and Address of
Beneficial Owner (1)
 
Beneficially
Owned (2)
 Percent of Class
Kelcy L. Warren (3)
 187,739,220
 17.4%
Ray C. Davis (4)
 70,058,606
 6.5%
John W. McReynolds (5)
 25,085,888
 2.3%
Thomas E. Long —
 *
Marshall S. (Mackie) McCrea, III 1,177,570
 *
Thomas P. Mason 583,000
 *
Brad Whitehurst (6)
 9,145
 *
Richard D. Brannon 38,400
 *
Matthew S. Ramsey 52,317
 *
K. Rick Turner (7)
 452,072
 *
William P. Williams (8)
 5,392,728
 *
All Directors and Executive Officers as a group (11 persons) 290,588,946
 26.9%
unless otherwise noted. The beneficial ownership of each listed person is based on 3,094,593,760 common units outstanding in the aggregate as of February 10, 2023.
*Less than 1%
(1)
The address for Mr. Davis is 5950 Sherry Lane, Dallas, Texas 75225. The address for all other listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.
(2)
Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct
(3)The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units and are not entitled to distributions and otherwise have no economic attributes. The Energy Transfer Class A Units are not convertible into, or exchangeable for, Partnership common units. Under the terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to the general partner additional Energy Transfer Class A Units such that Mr. Warren, through his majority ownership of our general partner, maintains the approximately 20% voting percentage in the Partnership represented by such Energy Transfer Class A Units equivalent to such Energy Transfer Class A Unit voting interest prior to such issuance of additional common units. This provision of the Energy Transfer Class A Units shall terminate at such time as Mr. Warren ceases to be an officer or director of our general partner, provided that all Energy Transfer Class A Units outstanding at such time shall be unchanged and remain outstanding. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(4)Includes 120,385,650 common units held by Kelcy Warren Partners, L.P. and 10,224,429 common units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 100,577,803 common units held by Kelcy Warren Partners III, LLC formerly known as Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 common units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 1,079,145,561 Common Units outstanding in the aggregate as of February 16, 2018. The number of Common Units shown does not include Common Units that may result from the conversion of ETE Series A Convertible Preferred Units, since such conversion is not expected to occur within sixty days of the date of this annual report.
(3)
Includes 79,102,200 Common Units held by Kelcy Warren Partners, L.P. and 8,244,900 Common Units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 73,853,812 Common Units held by Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 5,012 Common Units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and

dispositive power with Ray Davis. Also includes 601,076 Commoncommon units and 765,933,429 Energy Transfer Class A Units held by LE GP, LLC. Mr. Warren may be deemed to own Commoncommon units and Energy Transfer Class A Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. The voting and disposition of these Common Units is directly controlled by the board of directors of LE GP, LLC. Mr. Warren disclaims beneficial ownership of Commoncommon units and Energy Transfer Class A Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 84,000 Common Units104,166 common units held by Mr. Warren’s spouse. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(4)
Includes 41,692 Common Units held by Avatar Holdings LLC, 1,092,436 Common Units held by Avatar BW, Ltd., 22,742,680 Common Units held by Avatar ETC Stock Holdings LLC, 2,868,948 Common Units held by Avatar Investments LP, 97,668 Common Units held by Avatar Stock Holdings, LP and 817,216 Common Units held by RCD Stock Holdings, LLC, all of which entities are owned or controlled by Mr. Davis. Also includes 12,892,020 Common Units held by a remainder trust for Mr. Davis’ spouse and 7,689,900 Common Units held by two trusts for the benefit of Mr. Davis’ grandchildren, for which Mr. Davis serves as trustee. Mr. Davis shares voting and dispositive power with his wife with respect to Common Units held directly. Also includes 264,806 Common Units attributable to ET Company Ltd. Mr. Davis is a former executive officer of ETP and former director of our General Partner.
(5)
Includes 14,490,408 Common Units held by McReynolds Energy Partners L.P. and 10,086,280 Common Units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of Common Units
(5)Includes 297,617 common units held by Mr. Whitehurst in a margin account.
(6)Includes 1,544,558 common units held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee.
(7)Includes 580,000 common units held by B4 Capital Investments, LP, a limited partnership of which a limited liability company owned by Mr. Brannon and his wife is the sole general partner and of which Mr. Brannon and his wife are the sole limited partners.
(8)Includes 530,173 common units held Grimm Family Limited Partnership, a limited partnership of which a limited liability company owned by Mr. Grimm is the sole general partner.
(9)Includes 17,445,608 common units held by McReynolds Energy Partners L.P. and 12,142,593 common units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of common units owned by such limited partnerships other than to the extent of his interest in such entities.
(6)
Includes 4,430 Common Units held in a family trust. Mr. Whitehurst disclaims beneficial ownership of the Common Units held by such trust, except to the extent of his interest in such trust.
(7)
Includes (i) 89,084 Common Units held in a partnership controlled by the Stephens Group, Mr. Turner’s former employer; (ii) 8,000 Common Units held by the Turner Family Partnership; and (iii) 157,790 Common Units held by the Turner Liquidating Trust. The voting and disposition of the Common Units held by the Stephens Group partnership is controlled by the board of directors of the Stephens Group. With respect to the Common Units held by the Turner Family Partnership, Mr. Turner exercises voting and dispositive power as the general partner of the partnership; however, he disclaims beneficial ownership of these Common Units, except to the extent of his interest in the partnership. With respect to the Common Units held by the Turner Liquidating Trust, Mr. Turner exercises one-third of the shared voting and dispositive power with the administrator of the liquidating trust and Mr. Turner’s ex-wife, who beneficially owns an additional 157,790 Common Units. Mr. Turner disclaims beneficial ownership of the Common Units owned by his ex-wife.
(8)
Includes 2,338,484 Common Units held by the William P and Jane C Family Partnership Ltd. and 3,032,028 Common Units held by the Bar W Barking Cat LTD Partnership. Mr. Williams disclaims beneficial ownership of Common Units owned by such entities, except to the extent of his interest in such entities.
In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and securityextent of his interest in allsuch entities.
(10)This information is based on a Schedule 13G filed on February 9, 2023 by Blackstone Holdings I/II GP L.L.C. on behalf of ETE’sitself and Blackstone Inc., Blackstone Group Management L.L.C., and Stephen A. Schwarzman, each of which reported sole voting and dispositive power with respect to 160,737,127 Energy Transfer Common Units. The sole member of Blackstone Holdings I/II GP L.L.C. is Blackstone Inc. The sole holder of the other grantors’ tangibleSeries II preferred stock of Blackstone Inc. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and intangible assets.controlled by its founder, Stephen A. Schwarzman. The address for each reporting person identified in the February 9, 2023 filing was 345 Park Avenue, New York, NY 10154.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
At December 31, 2017, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
The Parent Company’sPartnership’s principal sources of cash flow are derived from cash flows from the operations of its subsidiaries, including its direct and indirect investments in the limited partner and general partner interests in ETPSunoco LP and Sunoco LP,USAC, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and cash flows from the operations of Lake Charles LNG.
ETP and Sunoco LP are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.services.
In connection with ETE’s 2014 acquisitionmaking its director independence determination, the Board considered business arrangements involving a director who owns equity interest in, and is the CEO of, Lake Charles LNG, ETP agreeda company that owns working interests in oil and gas wells, and affiliates of the Partnership who made nominal payments to continuethat company. None of the arrangements involved payments to provide management services for ETE through 2015the company of more than $1 million in relation to both Lake Charles LNG’s regasification facilityany of the past three fiscal years and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year forBoard determined that the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP throughrelationship did not impact the relinquishment of future incentive distributions, as discussed further in Note 8 to our consolidated financial statements.

Mr. McCrea, a current director of LE GP, LLC, our General Partner, is also a director and executive officer of ETP GP. In addition, Mr. Warren, the Chairman of our Board of Directors, is also a director and executive officer of ETP GP.director’s independence.
For a discussion of director independence, see Item“Item 10. “Directors,Directors, Executive Officers and Corporate Governance.”
155
As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The partnership agreementPartnership Agreement of ETEEnergy Transfer provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to ETE,Energy Transfer, approved by all the partners of ETEEnergy Transfer and not a breach by the General Partner or its Board of Directors of any duties they may owe ETEEnergy Transfer or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
The Parent Company has agreements with subsidiariesAdditional information on our related party transactions is included in Note 2 to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in ourPartnership’s consolidated financial statements.statements included in “Item 8. Financial Statements and Supplementary Data.”
ETP previously had an operating lease agreement with the former owners of ETG, including Mr. Warren and Mr. Davis. ETP paid these former owners $5 million in annual operating lease payments during the term of the lease and made a one-time payment of $8.8 million in August 2017 and we retained the equipment when the lease expired at that time. With respect to the related party transaction with ETG, the Conflicts Committee of ETP met numerous times prior to the consummation of the transaction to discuss the terms of the transaction. The committee made the determination that the sale of ETG to ETP was fair and reasonable to ETP and that the terms of the operating lease between ETP and the former owners of ETG are fair and reasonable to ETP.
ITEM 14. PRINCIPAL ACCOUNTINGACCOUNTANT FEES AND SERVICES
The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in millions):
 Years Ended December 31,
 20222021
Audit fees (1)
$10.8 $10.7 
Audit-related fees(2)
— 0.3 
Total$10.8 $11.0 
 Years Ended December 31,
 2017 2016
Audit fees (1)
$11.5
 $9.9
Audit-related fees (2)
—
 0.6
Tax fees (3)
—
 0.1
Total$11.5
 $10.6
(1)Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.
(2)Includes fees for financial due diligence related to acquisitions.
(1)
Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting.
(2)
Includes fees in 2016 for financial statement audits and interim reviews of subsidiary entities in connection with contribution and sale transactions. Includes fees in 2016 in connection with the service organization control report on Panhandle’s centralized data center.
(3)
Includes fees related to state and local tax consultation.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 20172022 and 20162021 were pre-approved by the Audit Committee in accordance with this policy.

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

156
PART IVSunoco LP Credit Facility
As of December 31, 2022, the Sunoco LP Credit Facility had $900 million of outstanding borrowings and $7 million in standby letters of credit and matures in July 2023. The amount available for future borrowings was $593 million at December 31, 2022. The weighted average interest rate on the total amount outstanding as of December 31, 2022 was 6.17%.
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULESUSAC Credit Facility
As of December 31, 2022, USAC had $646 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2022, USAC had $954 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $333 million. The weighted average interest rate on the total amount outstanding as of December 31, 2022 was 6.84%.
Covenants Related to Our Credit Agreements
The agreements relating to the Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The Five-Year Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
•incur indebtedness;
•grant liens;
•enter into mergers;
•dispose of assets;
•make certain investments;
•make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any Event of Default (as defined in the Five-Year Credit Facility);
•engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
•engage in transactions with affiliates; and
•enter into restrictive agreements.
The applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the Five-Year Credit Facility ranges from 0.125% to 0.300%. 
117
The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.00 to 1.00, which can generally be increased to 5.50 to 1.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.32 to 1.00 at December 31, 2022, as calculated in accordance with the credit agreement.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.
Covenants Related to Transwestern
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:
•grant liens;
•make certain loans or investments;
•incur additional indebtedness or guarantee other indebtedness;
•enter into transactions with affiliates;
•merge or consolidate;
•sell our assets; and
•make certain acquisitions.
The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:
•a minimum EBITDA to interest coverage ratio;
•a ratio of total secured indebtedness to EBITDA within a specified range; and
•a maximum funded debt to EBITDA ratio.
Covenants Related to the HFOTCO Tax Exempt Notes
The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds.
Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2022.
118
Cash Distributions
Cash Distributions Paid by Energy Transfer
Under its Partnership Agreement, Energy Transfer will distribute all of its Available Cash, as defined in the Partnership Agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriate to provide for future cash requirements.
Energy Transfer Common Unit Distributions
Distributions declared and paid with respect to Energy Transfer common units were as follows:
Quarter EndedRecord DatePayment DateRate
(a) The following documents are filed as a part of this Report:
Page
(1) Financial Statements – see Index to Financial Statements
F - 1
(2) Financial Statement Schedules – None
(3) Exhibits – see Index to Exhibits
149
(b) Exhibits - see Index to Exhibits
149
(c) Financial statements of affiliates whose securities are pledged as collateral - See Index to Financial Statements on page S-1.
S - 1
The Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in this Annual Report on Form 10-K and have been included herein.
The Parent Company’s interest in ETP GP also constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of ETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. ETP GP does not have substantive operations of its own; rather, ETP GP only owns the general partner interest in ETP.
As further discussed in Note 6 to the consolidated financial statements, as referenced in (a) above, the financial statements of ETP GP would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of ETP GP have been excluded from this Annual Report on Form 10-K.

ITEM 16. FORM 10-K SUMMARY
None.

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

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

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

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


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENERGY TRANSFER EQUITY, L.P.
By:LE GP, LLC,
its general partner
Date:February 23, 2018By:/s/    Thomas E. Long
Thomas E. Long
Group Chief Financial Officer (duly
authorized to sign on behalf of the registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:
SignatureTitleDate
/s/    John W. McReynoldsDirector and PresidentFebruary 23, 2018
John W. McReynolds(Principal Executive Officer)
/s/    Thomas E. LongGroup Chief Financial Officer (Principal Financial and Accounting Officer)February 23, 2018
Thomas E. Long
/s/    Kelcy L. WarrenDirector and Chairman of the BoardFebruary 23, 2018
Kelcy L. Warren
/s/    Richard D. BrannonDirectorFebruary 23, 2018
Richard D. Brannon
/s/    Marshall S. McCrea, IIIDirectorFebruary 23, 2018
Marshall S. McCrea, III
/s/    Matthew S. RamseyDirectorFebruary 23, 2018
Matthew S. Ramsey
/s/    K. Rick TurnerDirectorFebruary 23, 2018
K. Rick Turner
/s/    William P. WilliamsDirectorFebruary 23, 2018
William P. Williams




INDEX TO FINANCIAL STATEMENTS
Energy Transfer Equity, L.P. and Subsidiaries
Page
Report of Independent Registered Public Accounting Firm
F - 2
Consolidated Balance Sheets
F - 3
Consolidated Statements of Operations
December 31, 2020
F - 5
February 8, 2021February 19, 2021$0.1525 
March 31, 2021May 11, 2021May 19, 20210.1525 
Consolidated Statements of Comprehensive Income
June 30, 2021
F -
August 6, 2021August 19, 20210.1525 
September 30, 2021November 5, 2021November 19, 20210.1525 
Consolidated Statements of Equity
December 31, 2021
F - 7
February 8, 2022February 18, 20220.1750 
March 31, 2022May 9, 2022May 19, 20220.2000 
Consolidated Statements of Cash Flows
June 30, 2022
F - 9
August 8, 2022August 19, 20220.2300 
September 30, 2022November 4, 2022November 21, 20220.2650 
Notes to Consolidated Financial Statements
December 31, 2022
F - 11
February 7, 2023February 21, 20230.3050 



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

BoardThe total amounts of Directors of LE GP, LLCdistributions declared and
Unitholders of paid during the periods presented (all from Available Cash from Energy Transfer Equity, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership)Transfer’s operating surplus and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three yearsare shown in the period ended December 31, 2017, and the related notes (collectively referred to which they relate) are as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.follows:
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018 expressed an unqualified opinion thereon.
 Years Ended December 31,
 20222021
Limited Partners$3,089 $1,777 
General Partner interest3 2 
Total Energy Transfer distributions$3,092 $1,779 
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2004.


Dallas, Texas
February 23, 2018



ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$336
 $467
Accounts receivable, net4,504
 3,557
Accounts receivable from related companies53
 47
Inventories2,022
 2,055
Income taxes receivable136
 128
Derivative assets24
 21
Other current assets295
 447
Current assets held for sale3,313
 177
Total current assets10,683
 6,899
    
Property, plant and equipment71,177
 61,562
Accumulated depreciation and depletion(10,089) (7,984)
 61,088
 53,578
    
Advances to and investments in unconsolidated affiliates2,705
 3,040
Other non-current assets, net886
 815
Intangible assets, net6,116
 5,512
Goodwill4,768
 5,670
Non-current assets held for sale—
 3,411
Total assets$86,246
 $78,925
* As adjusted. See Note 2.



















ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,685
 $3,502
Accounts payable to related companies31
 42
Derivative liabilities111
 172
Accrued and other current liabilities2,582
 2,367
Current maturities of long-term debt413
 1,194
Current liabilities held for sale75
 —
Total current liabilities7,897
 7,277
    
Long-term debt, less current maturities43,671
 42,608
Long-term notes payable - related company—
 250
Deferred income taxes3,315
 5,112
Non-current derivative liabilities145
 76
Other non-current liabilities1,217
 1,075
Liabilities associated with assets held for sale—
 48
    
Commitments and contingencies

 

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









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


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
Net income$2,366
 $—
 $1,061
Other comprehensive income (loss), net of tax:     
Change in value of available-for-sale securities6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(12) (1) 65
Foreign currency translation adjustment—
 (1) (1)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
 (5) 4
 60
Comprehensive income2,361
 4
 1,121
Less: Comprehensive income (loss) attributable to noncontrolling interest1,407
 (991) (68)
Comprehensive income attributable to partners$954
 $995
 $1,189
* As adjusted. See Note 2.





































ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
 
General
Partner
 
Common
Unitholders
 Class D Units Series A Convertible Preferred Units 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interest
 Total
Balance, December 31, 2014*(1) 648
 22
 —
 (5) 21,637
 22,301
Distributions to partners(3) (1,084) (3) —
 —
 —
 (1,090)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 (2,335) (2,335)
Subsidiary units issued(1) (524) (1) —
 —
 4,415
 3,889
Conversion of Class D Units to ETE Common Units—
 7
 (7) —
 —
 —
 —
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 —
 8
 —
 —
 62
 70
Capital contributions received from noncontrolling interest—
 —
 —
 —
 —
 875
 875
Units repurchased under buyback program—
 (1,064) —
 —
 —
 —
 (1,064)
Acquisition and disposition of noncontrolling interest—
 —
 —
 —
 —
 (65) (65)
Other comprehensive income, net of tax—
 —
 —
 —
 5
 55
 60
Other, net—
 (118) —
 —
 —
 (31) (149)
Net income (loss)3
 1,183
 3
 —
 —
 (128) 1,061
Balance, December 31, 2015*(2) (952) 22
 —
 —
 24,485
 23,553
Distributions to partners(3) (1,019) —
 —
 —
 —
 (1,022)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 (2,795) (2,795)
Distributions reinvested—
 (173) —
 173
 —
 —
 —
Subsidiary units issued for cash—
 —
 —
 —
 —
 2,559
 2,559
Subsidiary units issued for acquisition—
 —
 —
 —
 —
 307
 307
Issuance of common units—
 39
 

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

PennTex unit acquisition—
 (2) —
 —
 —
 (278) (280)
Sale of Bakken Pipeline interest—
 42
 —
 —
 —
 1,958
 2,000
Sale of Rover Pipeline interest—
 2
 —
 —
 —
 1,476
 1,478
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 (5) (5)
Net income2
 915
 —
 37
 —
 1,412
 2,366
Balance, December 31, 2017$(3) $(1,643) $—
 $450
 $—
 $31,176
 $29,980
* As adjusted. See Note 2.

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
OPERATING ACTIVITIES:     
Net income$2,366
 $—
 $1,061
Reconciliation of net income to net cash provided by operating activities:     
Loss (income) from discontinued operations177
 462
 (38)
Depreciation, depletion and amortization2,554
 2,216
 1,951
Deferred income taxes(1,871) (177) 239
Amortization included in interest expense24
 3
 (21)
Unit-based compensation expense99
 70
 91
Impairment losses1,039
 1,040
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt89
 —
 43
Impairment of investments in unconsolidated affiliates313
 308
 —
Losses on disposal of assets—
 —
 (6)
Equity in earnings of unconsolidated affiliates(144) (270) (276)
Distributions from unconsolidated affiliates297
 268
 409
Inventory valuation adjustments(24) (97) 67
Other non-cash(298) (239) (8)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(192) (179) (872)
Net cash provided by operating activities4,429
 3,322
 2,979
INVESTING ACTIVITIES:     
Proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Proceeds from sale of Rover Pipeline interest1,478
 —
 —
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisitions, net of cash received(303) (1,398) (777)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Capital expenditures, excluding allowance for equity funds used during construction(8,444) (7,771) (9,073)
Contributions in aid of construction costs31
 71
 80
Contributions to unconsolidated affiliates(268) (68) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings135
 135
 128
Proceeds from the sale of other assets48
 35
 14
Change in restricted cash—
 14
 19
Other(3) —
 (16)
Net cash used in investing activities(5,606) (8,982) (9,735)
FINANCING ACTIVITIES:     
Proceeds from borrowings31,608
 25,785
 26,455
Repayments of long-term debt(31,268) (19,076) (19,828)
Cash received from affiliate notes—
 5,317
 —
Cash paid on affiliate notes(255) (5,051) —
Units issued for cash568
 —
 —
Subsidiary units issued for cash3,235
 2,559
 3,889
Distributions to partners(1,010) (1,022) (1,090)
Distributions to noncontrolling interests(2,961) (2,766) (2,335)
Redemption of ETP Convertible Preferred Units(53) —
 —
Debt issuance costs(131) (52) (75)
Capital contributions from noncontrolling interest1,214
 236
 841
Units repurchased under buyback program—
 —
 (1,064)
Other, net6
 (3) (8)
Net cash provided by financing activities953
 5,927
 6,785
DISCONTINUED OPERATIONS     
Operating activities136
 93
 90
Investing activities(38) (483) (360)

Changes in cash included in current assets held for sale(5) 5
 (13)
Net increase (decrease) in cash and cash equivalents of discontinued operations93
 (385) (283)
Decrease in cash and cash equivalents(131) (118) (254)
Cash and cash equivalents, beginning of period467
 585
 839
Cash and cash equivalents, end of period$336
 $467
 $585
* As adjusted. See Note 2.

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

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

References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The historical common units for ETP presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchangeSupplementary Data”, in connection with the Sunoco Logistics Merger.Rollup Mergers, ETO’s outstanding preferred units were converted into Energy Transfer Preferred Units on April 1, 2021.
For prior periods herein, certain transactions related
119
Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and their marketing affiliates. These reclassifications had no impact on net income Series H preferred units declared and/or total equity. Additionally, for prior periods herein, certain balances have been reclassified to assetspaid by Energy Transfer were as follows:
Period EndedRecord DatePayment Date
Series A (1)
Series B (1)
Series CSeries DSeries E
Series F (1)
Series G (1)
Series H (1)
March 31, 2021May 3, 2021May 17, 2021$—$—$0.4609$0.4766$0.4750$33.75$35.63$—
June 30, 2021August 2, 2021August 16, 202131.2533.130.46090.47660.4750———
September 30, 2021November 1, 2021November 15, 2021——0.46090.47660.475033.7535.6327.08*
December 31, 2021February 1, 2022February 15, 202231.2533.130.46090.47660.4750———
March 31, 2022May 2, 2022May 16, 2022——0.46090.47660.475033.7535.6332.50
June 30, 2022August 1, 2022August 15, 202231.2533.130.46090.47660.4750———
September 30, 2022November 1, 2022November 15, 2022——0.46090.47660.475033.7535.6332.50
December 31, 2022February 1, 2023February 15, 202331.2533.130.46090.47660.4750———
*    Represents prorated initial distribution.
(1)    Series A, Series B, Series F, Series G and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.
Business Operations
The Parent Company’s principal sources of cash flowSeries H distributions are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Companycurrently paid on a stand-alone basis, see Note 17 for stand-alone financial information apart from that ofsemi-annual basis. Pursuant to their terms, distributions on the consolidated partnership information included herein.
Our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG;Series A and
Corporate Series B preferred units will be paid quarterly beginning after February 15, 2023 and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
ETP is a publicly traded partnership whose operations comprise the following:
the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales;
intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia;
interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and
controlling interest in Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.February 15, 2028, respectively
Sunoco LP is engagedCash Distributions
Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s incentive distribution rights. As of December 31, 2022, Sunoco LP had approximately 84.1 million common units outstanding.
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the wholesalecolumn “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target AmountCommon UnitholdersHolder of IDRs
Minimum Quarterly Distribution $0.4375100%—%
First Target Distribution$0.4375 to $0.503125100%—%
Second Target Distribution$0.503125 to $0.54687585%15%
Third Target Distribution$0.546875 to $0.65625075%25%
ThereafterAbove $0.65625050%50%
120
Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP operated convenience stores and retail fuel sites.were as follows:
Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

2.Quarter Ended
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Record DatePayment DateRate
December 31, 2020February 8, 2021February 19, 2021$0.8255 
March 31, 2021May 11, 2021May 19, 20210.8255 
June 30, 2021August 6, 2021August 19, 20210.8255 
September 30, 2021November 5, 2021November 19, 20210.8255 
December 31, 2021February 8, 2022February 18, 20220.8255 
March 31, 2022May 9, 2022May 19, 20220.8255 
June 30, 2022August 8, 2022August 19, 20220.8255 
September 30, 2022November 4, 2022November 18, 20220.8255 
December 31, 2022February 7, 2023February 21, 20230.8255 
Change in Accounting Policy
During the fourth quarterThe total amount of 2017, ETP elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined product and NGL associated with the legacy Sunoco Logistics business. ETP’s management believes that the weighted-average cost method is preferabledistributions to the LIFO methodPartnership from Sunoco LP for the periods presented below is as it more closely alignsfollows:
Years Ended December 31,
20222021
Distributions from Sunoco LP
Limited Partner interests$94 $94 
General Partner interest and IDRs72 71 
Total distributions from Sunoco LP$166 $165 
USAC Cash Distributions
Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2022, USAC had approximately 98.2 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.
Distributions on USAC’s units declared and/or paid by USAC were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2020January 25, 2021February 5, 2021$0.5250 
March 31, 2021April 26, 2021May 7, 20210.5250 
June 30, 2021July 26, 2021August 6, 20210.5250 
September 30, 2021October 25, 2021November 5, 20210.5250 
December 31, 2021January 24, 2022February 4, 20220.5250 
March 31, 2022April 25, 2022May 6, 20220.5250 
June 30, 2022July 25, 2022August 5, 20220.5250 
September 30, 2022October 24, 2022November 4, 20220.5250 
December 31, 2022January 23, 2023February 3, 20230.5250 
The total amount of distributions to the Partnership from USAC for the periods presented below is as follows:
Years Ended December 31,
20222021
Distributions from USAC
Limited Partner interests$97 $97 
Total distributions from USAC$97 $97 
Critical Accounting Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting policies acrossrules have developed. Accounting rules generally do not involve a selection among alternatives,
121
but involve an implementation and interpretation of existing rules, and the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.
As a resultuse of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 Year Ended December 31, 2016 Year Ended December 31, 2015
 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted
Consolidated Statement of Operations and Comprehensive Income:           
Cost of products sold$23,652
 $41
 $23,693
 $28,636
 $32
 $28,668
Operating income1,884
 (41) 1,843
 2,319
 (32) 2,287
Income from continuing operations before income tax benefit245
 (41) 204
 932
 (32) 900
Net income41
 (41) —
 1,093
 (32) 1,061
Net income (loss) attributable to noncontrolling interest(954) (41) (995) (96) (32) (128)
Comprehensive income45
 (41) 4
 1,153
 (32) 1,121
            
Consolidated Statements of Cash Flows:           
Net income41
 (41) —
 1,093
 (32) 1,061
Inventory valuation adjustments(267) 170
 (97) 229
 (162) 67
Net change in operating assets and liabilities (change in inventories)(50) (129) (179) (1,066) 194
 (872)
            
Consolidated Balance Sheets (at period end):           
Inventories2,141
 (86) 2,055
 1,498
 (45) 1,453
Noncontrolling interest24,211
 (86) 24,125
 24,530
 (45) 24,485
* Amounts reflect certain reclassifications made to conformjudgment applied to the current year presentationspecific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and includewe believe the impactproper implementation and consistent application of discontinued operations asthe accounting rules are critical. Our critical accounting policies are discussed inbelow. For further details on our accounting policies see Note 3.2 to our consolidated financial statements.
Use of Estimates
. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices.prices for our intrastate transportation and storage segment, our midstream segment, and our NGL and refined products transportation and services segment. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results estimated for the year ended December 31, 2022 represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill

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

years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
Revenue Recognition
Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
Investment in ETP
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.
In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availabilityoccurrence of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.
Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and segment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.
ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result ofevents, changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

NGL storage and pipeline transportation revenues are recognized when services are performedcircumstances, or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.
In ETP’s natural gas compressionannual testing requirements. For business revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Investment in Sunoco LP
Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Sunoco LP may sell motor fuel to wholesale customers on a commission agent basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease.
Investment in Lake Charles LNG
Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.
Regulatory Accounting – Regulatory Assets and Liabilities
ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatorycombinations, assets and liabilities when it is probable that those expenses and revenues willare required to be allowedrecorded at estimated fair value in connection with the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessmentinitial recognition of the probability of recovery or pass through of regulatorytransaction. For impairment testing, long-lived assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If,are required to be tested for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:
 Years Ended December 31,
 2017 2016 2015
Accounts receivable$(948) $(1,126) $856
Accounts receivable from related companies24
 42
 (5)
Inventories58
 (480) (212)
Other current assets38
 165
 (225)
Other non-current assets, net84
 (148) 247
Accounts payable712
 1,170
 (1,070)
Accounts payable to related companies(178) (64) 400
Accrued and other current liabilities(97) 89
 (697)
Other non-current liabilities106
 106
 (241)
Derivative assets and liabilities, net9
 67
 75
Net change in operating assets and liabilities, net of effects of acquisitions$(192) $(179) $(872)
Non-cash investing and financing activities and supplemental cash flow information were as follows:
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,060
 $848
 $910
Net gains (losses) from subsidiary common unit transactions(56) 16
 (526)
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Contribution of assets from noncontrolling interest988
 —
 34
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,914
 $1,922
 $1,800
Cash paid for (refund of) income taxes50
 (229) 72
Accounts Receivable
Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.

Inventories
As discussed under “Change in Accounting Policy” in Note 2, ETP changed its accounting policy for certain inventory in the fourth quarter of 2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.
Inventories consisted of the following:
 December 31,
 2017 2016
Natural gas, NGLs, and refined products$1,120
 $1,141
Crude oil551
 651
Spare parts and other351
 263
Total inventories$2,022
 $2,055
ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.
Other Current Assets
Other current assets consisted of the following:
 December 31,
 2017 2016
Deposits paid to vendors$64
 $74
Prepaid expenses and other231
 373
Total other current assets$295
 $447
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairmentrecoverability whenever events or changes in circumstances indicate that the carrying amount of such assetsthe asset may not be recoverable. If such a review shouldGoodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017, ETP recorded a $127 million fixedrelated asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, ETP recorded a $133 million fixed asset impairment related to its interstate transportation and storage operations primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in its midstream operations. In 2015, ETP recorded a $110 million fixed asset impairment related to its NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for its reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our

revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Components and useful lives of property, plant and equipment were as follows:
 December 31,
 2017 2016
Land and improvements$2,222
 $1,189
Buildings and improvements (1 to 45 years)2,786
 2,247
Pipelines and equipment (5 to 83 years)44,673
 36,570
Natural gas and NGL storage facilities (5 to 46 years)1,681
 1,451
Bulk storage, equipment and facilities (2 to 83 years)3,883
 3,701
Vehicles (1 to 25 years)126
 217
Right of way (20 to 83 years)3,432
 3,349
Natural resources434
 434
Other (1 to 40 years)1,029
 2,285
Construction work-in-process10,911
 10,119
 71,177
 61,562
Less – Accumulated depreciation and depletion(10,089) (7,984)
Property, plant and equipment, net$61,088
 $53,578
We recognized the following amounts for the periods presented:
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,204
 $1,952
 $1,661
Capitalized interest286
 201
 164
Advances to and Investments in Affiliates
Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
 December 31,
 2017 2016
Regulatory assets85
 86
Deferred charges210
 217
Restricted funds192
 190
Other399
 322
Total other non-current assets, net$886
 $815
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
 December 31, 2017 December 31, 2016
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:       
Customer relationships, contracts and agreements (3 to 46 years)$6,979
 $(1,277) $6,050
 $(971)
Trade names (20 years)66
 (25) 66
 (22)
Patents (10 years)48
 (26) 48
 (21)
Other (5 to 20 years)28
 (14) 25
 (10)
Total amortizable intangible assets7,121
 (1,342) 6,189
 (1,024)
Non-amortizable intangible assets:       
Trademarks295
 —
 288
 —
Other42
 —
 59
 —
Total intangible assets$7,458
 $(1,342) $6,536
 $(1,024)
Aggregate amortization expense of intangibles assets was as follows:
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$344
 $264
 $290
Estimated aggregate amortization expense of intangible assets for the next five years was as follows:
Years Ending December 31: 
2018$341
2019338
2020336
2021319
2022287
We review amortizable intangible assets for An impairment whenever events or changes in circumstances indicate thatloss should be recognized only if the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assetsasset/goodwill is not recoverable we reduce the carrying amount of such assets toand exceeds its fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

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

Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.
Changes in the carrying amount of goodwill were as follows:
 Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total
Balance, December 31, 2015$5,428
 $1,694
 $184
 $(1,250) $6,056
Goodwill acquired428
 81
 —
 —
 509
Sunoco LP Exchange(1,289) —
 —
 1,289
 —
Goodwill impairment(670) (227) —
 —
 (897)
Other—
 2
 —
 —
 2
Balance, December 31, 20163,897
 1,550
 184
 39
 5,670
  Goodwill acquired12
 —
 —
 —
 12
  Goodwill impairment(793) (102) —
 —
 (895)
  Other(1) (18) —
 —
 (19)
Balance, December 31, 2017$3,115
 $1,430
 $184
 $39
 $4,768
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, ETP recognized goodwill impairments of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2016, ETP recognized goodwill impairments of $638 million in its interstate transportation and storage operations and $32 million in its midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2015, ETP recognized goodwill impairments of $99 million in its interstate transportation and storage operations and $106 million in its NGL and refined products transportation and services operations primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determinedCalculating the fair value of assets or reporting units in connection with business combination accounting or impairment testing requires management to make several estimates, assumptions and judgements, and in some circumstances management may also utilize third-party specialists to assist and advise on those calculations.
In order to allocate the purchase price in a business combination or to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of commodities, our ability to negotiate favorable sales agreements, the risks that exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.
The Partnership determines the fair value of its assets and/or reporting units using a weighted combination of the discounted cash flow method, and the guideline company method.method, the reproduction and replacement methods, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our business combination accounting and impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determineddetermines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determineddetermines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s
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projected EBITDA and then averaging that estimate with similar historical calculations using a three yearmulti-year average. In addition, the Partnership estimatedestimates a reasonable control premium, when appropriate, representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates Under the reproduction and assumptions related to retirement costs, whichreplacement methods, the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts discussed below, management was not able to reasonably measuredetermines the fair value of assets based on the estimated installation, engineering, and set-up costs related to the asset; these methods require the use of trend factors, such as inflation indices.
One key assumption in these fair value calculations is management’s estimate of future cash flows and EBITDA. In accounting for a business combination, these estimates are generally based on the forecasts that were used to analyze the deal economics. For impairment testing, these estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for business combination accounting and impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in changes to the fair value estimates used in business combination accounting, which could significantly impact results of operations in a period subsequent to the business combination, depending on multiple factors, including the timing of such changes. In the case of impairment testing, such changes could result in additional impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments.
In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also result in an impairment or impact the magnitude of an impairment.
During the years ended December 31, 2022, 2021 and 2020, the Partnership recorded total assets of $1.38 billion, $8.58 billion and $12 million, respectively, in connection with business combinations.
During the years ended December 31, 2022, 2021 and 2020, the Partnership recorded impairments totaling $386 million, $21 million and $3.01 billion, respectively, including $129 million in impairments in unconsolidated affiliates in 2020, and $5 million and $66 million of long-lived asset retirement obligationsimpairments in 2021 and 2020, respectively. Additional information on the impairments recorded during these periods is available in “Item 8. Financial Statements and Supplementary Data.”
Management does not believe that any of the Partnership’s goodwill balances, long-lived assets or investments in unconsolidated affiliates is currently at significant risk of a material impairment; however, of the $2.57 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 20172022, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.
Estimated Useful Lives of Long-Lived Assets. Depreciation and 2016,amortization of long-lived assets is provided using the straight-line method based on their estimated useful lives. Changes in most cases because the settlement dates were indeterminable. Althoughestimated useful lives of the assets could have a numbermaterial effect on our results of other onshoreoperation. The Partnership’s results of operations have not been significantly impacted by changes in the estimated useful lives of our long-lived assets during the periods presented, and we do not anticipate any such significant changes in Panhandle’s systemthe future. However, changes in facts and circumstances could cause us to change the estimated useful lives of the assets, which could significantly impact the Partnership’s results of operations. Additional information on our accounting policies and the estimated useful lives associated with our long-lived assets is available in “Item 8. Financial Statements and Supplementary Data.”
Legal and Regulatory Matters. We are subject to agreementslitigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or regulationssettlements. To the extent that give riseactual outcomes differ from our estimates, or additional facts and circumstances cause us to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligationsrevise our estimates, our earnings will be settled. Consequently,affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the retirement obligations for these assets cannot be measured at this time. Atopinions and views of our legal counsel; (ii) our previous experience; and (iii) the enddecision of our management as to how we intend to respond to the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
complaints. As of December 31, 20172022 and 2016, other non-current liabilities in ETP’s consolidated balance sheets included AROs2021, accruals of $165$200 million and $170$144 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated to $2 million and $14 million, andrespectively, were reflected as property, plant and equipment on our consolidated balance sheets as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
All amounts recorded in our consolidated balance sheets as of December 31, 2017 and 2016 are attributablerelated to the obligations of ETP.these contingent obligations.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
 December 31,
 2017 2016
Interest payable$552
 $545
Customer advances and deposits59
 72
Accrued capital expenditures1,006
 769
Accrued wages and benefits280
 254
Taxes payable other than income taxes108
 201
Income taxes payable180
 —
Exchanges payable154
 208
Other243
 318
Total accrued and other current liabilities$2,582
 $2,367

Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of ETP’s consolidated subsidiaries have the option to sell their interests to ETP.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interestFor more information on our litigation and contingencies, see Note 11 to our consolidated balance sheet.financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.
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Environmental Remediation
We accrue Activities. The Partnership’s accrual for environmental remediation costs foractivities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals areThe accrual for known claims is undiscounted and areis based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. IfIt is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. The Partnership’s estimates of environmental remediation costs also frequently involve evaluation of a range of probable environmental cleanup costs exists for an identified site,estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range is accrued unless some other point inbe accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $282 million and $293 million in environmental accruals as of December 31, 2022 and 2021, respectively.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.
Deferred Income Taxes. Energy Transfer recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal excess business interest expense carryforwards totaling $603 million have been included in Energy Transfer’s consolidated balance sheet as of December 31, 2022. The state NOL carryforward benefits of $104 million ($82 million net of federal benefit) began expiring in 2023 with a substantial portion expiring between 2033 and 2039. Energy Transfer’s corporate subsidiaries have federal NOLs of $2.4 billion ($496 million in benefits) of which $645 million will expire between 2036 and 2037. A total of $341 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. We have determined that a valuation allowance totaling $4 million ($3 million net of federal income tax effects) is required for state NOLs as of December 31, 2022 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $15 million is attributable to foreign tax credits. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.
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Forward-Looking Statements
This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
•the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;
•the actual amount of cash distributions by our subsidiaries to us;
•the volumes transported on our subsidiaries’ pipelines and gathering systems;
•the level of throughput in our subsidiaries’ processing and treating facilities;
•the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
•the prices and market demand for, and the relationship between, natural gas and NGLs;
•energy prices generally;
•impacts of world health events, including the COVID-19 pandemic;
•the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
•the general level of petroleum product demand and the availability and price of NGL supplies;
•the level of domestic oil, natural gas and NGL production;
•the availability of imported oil, natural gas and NGLs;
•actions taken by foreign oil and gas producing nations;
•the political and economic stability of petroleum producing nations;
•the effect of weather conditions on demand for oil, natural gas and NGLs;
•availability of local, intrastate and interstate transportation systems;
•the continued ability to find and contract for new sources of natural gas supply;
•availability and marketing of competitive fuels;
•the impact of energy conservation efforts;
•energy efficiencies and technological trends;
•governmental regulation and taxation;
•changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•competition from other midstream companies and interstate pipeline companies;
•loss of key personnel;
•loss of key natural gas producers or the providers of fractionation services;
•reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;
•the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;
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•the nonpayment or nonperformance by our subsidiaries’ customers;
•regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems;
•risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
•the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;
•a deterioration of the credit and capital markets;
•risks associated with the assets and operations of entities in which case our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;
•the most likely amountability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
•changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and
•the rangecosts and effects of legal and administrative proceedings.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Basedbased only on the estimated borrowing ratesinformation currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligationsspeaks only as of December 31, 2017 was $45.62 billionthe date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(Tabular dollar amounts are in millions)
Market risk includes the risk of loss arising from adverse changes in market rates and $44.08 billion, respectively. As of December 31, 2016, the aggregate fair valueprices. We face market risk from commodity variations, risk and carrying amount ofinterest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our consolidated debt obligations was $45.05 billion and $43.80 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.exposure to such risks.
Commodity Price Risk
We haveare exposed to market risks related to the volatility of commodity derivatives, interest rate derivativesprices. To manage the impact of volatility from these prices, we utilize various exchange-traded and embedded derivatives in the ETP Convertible Preferred Units thatOTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are accounted for as assets and liabilitiesrecorded at fair value in our consolidated balance sheets.
We determine theuse futures and basis swaps, designated as fair value ofhedges, to hedge our assetsnatural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off-peak season and liabilities subject to fair value measurement by usingentering into a financial contract. Changes in the highest possible “level” of inputs. Level 1 inputs are observable quotesspreads between the forward natural gas prices and the physical inventory spot price result in an active market for identical assetsunrealized gains or losses until the underlying physical gas is withdrawn and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of theserelated designated derivatives are quotedsettled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futuresindex price for the same periodresidue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the future interest swap settlements. Level 3 inputsrisk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are unobservable. During the year ended December 31, 2017 and 2016, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basisnot designated as of December 31, 2017 and 2016 based on inputs used to derive their fair values:hedges for accounting purposes.
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   Fair Value Measurements at
   December 31, 2017
 
Fair Value
Total
 Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$11
 $11
 $—
Swing Swaps IFERC13
 —
 13
Fixed Swaps/Futures70
 70
 —
Forward Physical Swaps8
 —
 8
Power — Forwards23
 —
 23
Natural Gas Liquids — Forwards/Swaps193
 193
 —
Refined Products – Futures1
 1
 —
Crude – Futures2
 2
 —
Total commodity derivatives321
 277
 44
Other non-current assets21
 14
 7
Total assets$342
 $291
 $51
Liabilities:     
Interest rate derivatives$(219) $—
 $(219)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(24) (24) —
Swing Swaps IFERC(15) (1) (14)
Fixed Swaps/Futures(57) (57) —
Forward Physical Swaps(2) —
 (2)
Power — Forwards(22) —
 (22)
Natural Gas Liquids — Forwards/Swaps(192) (192) 

Refined Products – Futures(28) (28) —
Crude — Futures(1) (1) —
Total commodity derivatives(341) (303) (38)
Total liabilities$(560) $(303) $(257)

   Fair Value Measurements at
   December 31, 2016
 
Fair Value
Total
 Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $—
 $—
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Contracts1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options — Calls1
 1
 —
 —
Natural Gas Liquids — Forwards/Swaps233
 233
 —
 —
Refined Products – Futures2
 2
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives363
 356
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$376
 $364
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the ETP Convertible Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) 

 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids — Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(23) (23) —
 —
Crude — Futures(13) (13) —
 —
Total commodity derivatives(478) (470) (8) —
Total liabilities$(672) $(470) $(201) $(1)
ContributionsWe use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in Aidmargins for certain refined products and to lock in the price of Construction Cost
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majoritynatural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of such arrangementsmarket opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold except for shippingin our consolidated statements of operations. We also have trading and handling costsmarketing activities related to fuel consumed for compressionpower and treatingnatural gas in our all other segment which are includedalso netted in operating expenses.

Costs and Expenses
Costscost of products sold include actual costsold. As a result of fuel sold, adjusted for the effects of hedging and other commodity derivativeour trading activities and the costuse of appliances, partsderivative financial instruments in our intrastate transportation and fittings. Operating expenses include all costs incurredstorage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to provide productsperiod. We attempt to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costsmanage this volatility through the use of daily position and plant operations. Selling, generalprofit and administrative expenses include all partnership related expensesloss reports provided to our risk oversight committee, which includes members of senior management, and compensation for executive, partnership,the limits and administrative personnel.authorizations set forth in our commodity risk management policy.
We recordThe following tables summarize commodity-related financial derivative instruments, fair values and the collectioneffect of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expensesan assumed hypothetical 10% change in the consolidated statementsunderlying price of operations, with no effect on net income (loss). Excise taxes collected by Sunoco LP’s retail locations where Sunoco LP holds the inventory were $234 million, $243 million and $231 million for the years endedcommodity as of December 31, 2017, 20162022 and 2015, respectively.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between2021 for the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. The Partnership and its corporate subsidiaries accountconsolidated subsidiaries. Dollar amounts are presented in millions.
December 31, 2022December 31, 2021
Notional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% ChangeNotional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures145 $— $— 585 $— $— 
Basis Swaps IFERC/NYMEX(1)
(39,563)54 3 (66,665)(5)1 
Power (Megawatt):
Forwards— 1 — 653,000 2 — 
Futures(21,384)— — (604,920)2 2 
Options – Puts119,200 — — (7,859)— — 
Options – Calls— — — (30,932)— — 
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX42,440 (41)4 6,738 1 1 
Swing Swaps IFERC(202,815)63 7 (106,333)32 31 
Fixed Swaps/Futures(15,758)51 7 (63,898)(24)38 
Forward Physical Contracts2,423 8 1 (5,950)1 — 
NGL (MBbls) – Forwards/Swaps6,934 (41)63 8,493 12 19 
Crude (MBbls) – Forwards/Swaps795 26 22 3,672 13 2 
Refined Products (MBbls) – Futures(3,547)(39)37 (3,349)(15)32 
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX(37,448)22 2 (40,533)1 — 
Fixed Swaps/Futures(37,448)58 17 (40,533)41 14 
(1)Includes aggregate amounts for income taxes under the assetopen positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.Henry Hub locations.
The determinationfair values of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain taxcommodity-related financial positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information broker quotes and appropriate valuation techniques.

At inception Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a hedge, we formally document the relationshiptheoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the hedging instrument
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contractual price of the instruments and the hedged item,underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inceptionevent of the hedge and on a quarterly basis, whether the derivatives that are usedan actual 10% change in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes inprompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the derivativefinancial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
Interest Rate Risk
As of December 31, 2022, our subsidiaries had $3.16 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in net income for the period.
If we designate a commodity hedging relationship asmaximum potential change to interest expense of $32 million annually; however, our actual change in interest expense may be less in a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is alsogiven period due to interest rate floors included in the cost of products sold in the consolidated statement of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
our variable rate debt instruments. We previously have managedmanage a portion of our interest rate exposuresexposure by utilizing interest rate swaps, and similar instruments. Forincluding forward-starting interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portionsswaps to lock-in the rate on a portion of those hedges in interest expense. Foranticipated debt issuances.
The following table summarizes our interest rate derivatives notswaps outstanding, none of which were designated as hedges for accounting purposes we report realized(dollar amounts presented in millions):
Term
Type(1)
Notional Amount Outstanding
December 31, 2022December 31, 2021
July 2022 (2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate$— $400 
July 2023 (2)(3)
Forward-starting to pay a fixed rate of 3.845% and receive a floating rate— 200 
July 2024 (2)
Forward-starting to pay a fixed rate of 3.512% and receive a floating rate400 200 
(1)Floating rates are based on either SOFR or three-month LIBOR.
(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
(3)This interest rate swap was terminated and unrealizedsettled in 2022.
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on those derivatives in “Gains (losses) on interest rate derivatives”derivatives) of $73 million as of December 31, 2022. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements starting on page F-1 of this report are incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of our management, including Marshall S. McCrea, III and Thomas E. Long, Co-Chief Executive Officers of our General Partner (Co-Principal Executive Officers), and Dylan A. Bramhall (Principal Financial Officer), of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including Messrs. McCrea, Long and Bramhall, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2022.
Management’s Report on Internal Control over Financial Reporting
The management of Energy Transfer LP and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).
Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2022.
Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2022, as stated in their report, which is included herein.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of operations.the Partnership as of and for the year ended December 31, 2022, and our report dated February 17, 2023 expressed an unqualified opinion on those financial statements.
Unit-BasedBasis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP
Dallas, Texas
February 17, 2023
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Changes in Internal Controls over Financial Reporting
There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2022 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of Energy Transfer are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement.
As of January 1, 2023, our Board of Directors is comprised of nine persons, four of whom qualify as “independent” under the NYSE’s corporate governance standards. As a limited partnership, we are not required under the NYSE’s corporate governance standards (Section 303A) to have a majority of independent directors. We have determined that Messrs. Anderson, Brannon, Grimm and Perry are all “independent” under the NYSE’s corporate governance standards.
As a limited partnership, we are not required by the rules of the NYSE to seek Unitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of Energy Transfer, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of Energy Transfer.
Board Leadership Structure. We have no policy requiring either that the positions of the Chairman of the Board and the Chief Executive Officer, or CEO, be separate or that they be occupied by the same individual. The Board of Directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances. Previously, the Board of Directors believed that the CEO was best situated to serve as Chairman because he was the director most familiar with the Partnership’s business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Beginning in 2021, the Board of Directors has established separate roles for the Executive Chairman and Co-Chief Executive Officers. Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and from a variety of industries, while the Executive Chairman and Co-Chief Executive Officers bring extensive experience and expertise specifically related to the Partnership’s business.
Risk Oversight. Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Co-CEOs, who report to the Board of Directors, have day-to-day risk management responsibilities. Our Co-CEOs attend the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of Energy Transfer’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from Energy Transfer’s internal auditor, who reports directly to the Audit Committee, and reviews Energy Transfer’s contingencies with management and our independent auditors.
Corporate Governance
The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.
Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.
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Annual Certification
In 2022, our Chief Executive Officer provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards.
Conflicts Committee
Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to Energy Transfer and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to Energy Transfer to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to Energy Transfer. Pursuant to the terms of our Partnership Agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Energy Transfer, approved by all partners of Energy Transfer and not a breach by the general partner or its Board of Directors of any duties they may owe Energy Transfer or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Audit Committee
The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Michael K. Grimm qualified as an audit committee financial expert during 2022. A description of the qualifications of Mr. Grimm may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”
The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and approves the filing of our Form 10-K, which includes our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of Energy Transfer be included in Energy Transfer’s Annual Report on Form 10-K for the year ended December 31, 2022.
The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Grimm serve as elected members of the Audit Committee.
Compensation and Nominating/Corporate Governance Committees
Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Messrs. Anderson and Grimm serve as members of the Compensation Committee.
The responsibilities of the Energy Transfer Compensation Committee include, among other duties, the following:
•annually review and approve goals and objectives relevant to compensation of our Co-CEOs and CFO, if applicable;
•annually evaluate the CEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO and CFO’s compensation levels, if applicable, based on this evaluation;
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•make determinations with respect to the grant of equity-based awards to executive officers under Energy Transfer’s equity incentive plans;
•periodically evaluate the terms and administration of Energy Transfer’s long-term incentive plans to assure that they are structured and administered in a manner consistent with Energy Transfer’s goals and objectives;
•periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
•periodically evaluate the compensation of the directors;
•retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO and CFO or executive officer compensation; and
•perform other duties as deemed appropriate by the Board of Directors.
Code of Business Conduct and Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the co-principal executive officers, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.
Meetings of Non-management Directors and Communications with Directors
Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.
We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer LP, 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.
Directors and Executive Officers of Our General Partner
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of February 17, 2023. Executive officers and directors are elected for indefinite terms.
NameAgePosition with Our General Partner
Kelcy L. Warren67 Executive Chairman of the Board of Directors
Thomas E. Long66 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
Marshall S. (Mackie) McCrea, III63 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
Dylan A. Bramhall46 Group Chief Financial Officer (Principal Financial Officer)
Thomas P. Mason66 Executive Vice President and President - LNG
Bradford D. Whitehurst48 Executive Vice President of Tax and Corporate Initiatives
James M. Wright, Jr.54 Executive Vice President, General Counsel and Chief Compliance Officer
A. Troy Sturrock52 Group Senior Vice President and Controller (Principal Accounting Officer)
Steven R. Anderson73 Director
Richard D. Brannon64 Director
Michael K. Grimm68 Director
John W. McReynolds72 Director
James R. (Rick) Perry72 Director
Matthew S. Ramsey67 Director
Mr. Long, Mr. Mason and Mr. Whitehurst serve as directors of the general partner of USAC.
Set forth below is biographical information regarding the foregoing officers and directors of our general partner:
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Kelcy L. Warren. Mr. Warren serves as Executive Chairman of our general partner. Mr. Warren served as Chief Executive Officer from August 2007 through December 2020. He was appointed Co-Chairman of the Board of Directors of our general partner, effective upon the closing of our IPO, and in August 2007, he became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general partner of ETO until its merger into Energy Transfer LP in April 2021. Prior to August 2007, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETO since the combination of the midstream and intrastate transportation storage operations of La Grange Acquisition, L.P. and the retail propane operations of Heritage in January 2004. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Warren was selected to serve as a director and as Executive Chairman because he previously served as Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States and brings a unique and valuable perspective to the Board of Directors.
Thomas E. Long. Mr. Long has served as the Co-Chief Executive Officer of our general partner since January 2021. Mr. Long served as Chief Financial Officer of Energy Transfer’s general partner from February 2016 until January 2021, and has been a director of our general partner since April 2019. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Chief Financial Officer of ETO until its merger into Energy Transfer LP in April 2021, and was previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. Mr. Long served as a director of Sunoco LP from May 2016 until May 2021, and has served on the Board of USAC since April 2018. In May 2022, Mr. Long was appointed to the board of directors of Texas Capital Bancshares, Inc (NASDAQ: TCBI). Mr. Long was selected to serve on our Board of Directors because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.
Marshall S. (Mackie) McCrea, III. Mr. McCrea has served as the Co-Chief Executive Officer of our general partner since January 2021. Prior to that he was the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of the Energy Transfer family since November 2015. Mr. McCrea has served on the Board of Directors of our general partner since December 2009. Mr. McCrea was appointed as a director of the general partner of ETO in December 2009 and served in that capacity until ETO’s merger into Energy Transfer LP in April 2021. Prior to December 2009, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017. Mr. McCrea was selected to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.
Dylan A. Bramhall. Mr. Bramhall has served as Group Chief Financial Officer of our general partner since November 2022 and currently is also Chief Financial Officer of Sunoco LP’s general partner. Mr. Bramhall joined Energy Transfer in 2015 as a result of its merger with Regency Energy Partners and is responsible for oversight of the Partnership’s Financial Planning and Analysis, Credit and Commodity Risk Management, Insurance, Cash Management, Capital Markets, Accounting, Financial Reporting and Investor Relations groups. He also serves as a member of Energy Transfer’s Risk Oversight Committee. While at Regency, Mr. Bramhall held management positions in the finance, risk, commercial and operations groups. Mr. Bramhall holds a Bachelor of Business Administration in finance and Master of Business Administration in finance and operations management, both from the University of Iowa.
Thomas P. Mason.Mr. Mason has served as Executive Vice President and President - LNG since December 2022. He became Executive Vice President and General Counsel of the general partner of Energy Transfer in December 2015, and served as the Executive Vice President, General Counsel and President - LNG from October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. until December 2022 when he resigned from his role as General Counsel. In February 2021, Mr. Mason assumed leadership responsibility over the Partnership’s newly created Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce Energy Transfer’s environmental footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining Energy Transfer, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason served as a director on the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017 and as a director on the Board of Directors of PennTex Midstream
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Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason has also served as a member of the Board of Directors of USAC since April 2018.
Bradford D. Whitehurst. Mr. Whitehurst has served as Executive Vice President of Tax and Corporate Initiatives of Energy Transfer since November 2022. From January 2021 to November 2022, he served as Chief Financial Officer. From August 2014 through December 2020, he served as Executive Vice President – Head of Tax. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer and its subsidiaries in his role as outside counsel since 2006. He has served as a member of the board of directors of USAC since April 2019.
James M. Wright, Jr. Mr. Wright was appointed as Executive Vice President, General Counsel and Chief Compliance Officer of our general partner in December 2022. He became Executive Vice President - Legal and Chief Compliance Officer of ET’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Wright has been a part of the Energy Transfer legal team with increasing levels of responsibility since July 2005 and has held various senior-level positions in the legal department including General Counsel of the general partner of Energy Transfer Partners, L.P. from December 2015 to October 2018 and Deputy General Counsel from May 2008 to December 2015. Prior to joining Energy Transfer, Mr. Wright gained significant experience at Enterprise Products Partners, L.P., El Paso Corp., Sonat Exploration Company and KPMG Peat Marwick LLP. Mr. Wright earned a Bachelor of Business Administration degree in Accounting and Finance from Texas A&M University and a JD from South Texas College of Law.
A. Troy Sturrock. Mr. Sturrock has served as the Group Senior Vice President, Controller and Principal Accounting Officer of our general partner since September 2022. He previously served as Senior Vice President, Controller and Principal Accounting Officer, having assumed that role in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He served as the Senior Vice President, Controller and Principal Accounting Officer of the general partner of ETO from August 2016 until ETO’s merger into Energy Transfer LP in April 2021, and previously served as Vice President, Controller and Principal Accounting Officer of our general partner beginning in June 2015. Mr. Sturrock is a Certified Public Accountant.
Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon’s Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. Mr. Anderson also served as a member of the board of directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. Mr. Anderson was selected to serve on our Board of Directors based on his experience in the midstream energy industry generally, and his knowledge of Energy Transfer’s business specifically. Mr. Anderson also brings recent experience on audit and compensation committees of another publicly traded partnership.
Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the audit committee since April 2016. Mr. Brannon is the CEO of CH4 Energy Six, LLC and Uinta Wax, LLC, both independent companies focused on horizontal oil and gas development. Mr. Brannon previously served on the board of directors of WildHorse Resource Development from its IPO in December 2016 until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Sunoco LP, Regency, OEC Compression and Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business, having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.
Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and served on the audit and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held upstream exploration and production company active in onshore continental United States, and served as its President and Chief Executive Officer from 1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018. From November 2018 until it was sold in 2019, Mr. Grimm served on the Board of Directors of Anadarko Petroleum Corporation. Prior to the formation of Rising Star,
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Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr. Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the American Association of Professional Landmen, Dallas Wildcat Committee, Dallas Producers Club, and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. Mr. Grimm was selected to serve as a director because of his extensive experience in the energy industry and his service as a senior executive at several energy-related companies, in addition to his contacts in the industry gained through his involvement in energy-related organizations.
John W. McReynolds. Mr. McReynolds is a director of Energy Transfer LP, having served in that capacity since August 2004. Mr. McReynolds previously served as the President of Energy Transfer LP from March 2005 until October 2018, at which time he became Special Advisor to the Partnership. Mr. McReynolds also previously served as our Chief Financial Officer from August 2005 to June 2013. Prior to becoming President of Energy Transfer LP, Mr. McReynolds was a partner in the international law firm of Hunton & Williams LLP for over 20 years. As a lawyer, he specialized in energy related finance, securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation, and governmental proceedings, including as an expert in special projects for boards of directors of public companies. Mr. McReynolds was selected to serve in the indicated roles with Energy Transfer because of this extensive background and experience, as well as his many contacts and relationships in the industry.
James R. (Rick) Perry. Mr. Perry was appointed to the Board of Directors of our general partner in January 2020. He formerly served as U.S. Secretary of Energy from March 2017 until December 2019. Prior to that, he served as the Governor of the State of Texas from 2000 until January 2015. Mr. Perry served as Lieutenant Governor of Texas from 1998 to 2000, and as Agriculture Commissioner from 1991 to 1998. Prior to 1991, he also served in the Texas House of Representatives. Mr. Perry previously served on the Board of Directors of ETO from February 2015 until December 2016. Mr. Perry was selected to serve as a director because of his vast experience as an executive in the highest office of state government. In addition, Mr. Perry has been involved in finance and budget planning processes throughout his career in government as a member of the Texas House Appropriations Committee, the Legislative Budget Board and as Governor.
Matthew S. Ramsey. Mr. Ramsey was appointed as a director of Energy Transfer’s general partner in July 2012 and served as a director of ETO’s general partner from November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey served as the Chief Operating Officer or our general partner from October 2018 until his retirement in April 2022, and served as President and Chief Operating Officer of ETO’s general partner from November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey also previously served as a director of Sunoco LP, having served as chairman of Sunoco LP’s board from April 2015 until March 2022, and of USAC, having served on that board from April 2018 until March 2022. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. In addition to his work in the energy business, Mr. Ramsey serves on the board of directors of the National Association of Manufacturers and as a Trustee of the Southwestern Medical Foundation. He is the former Chairman of the University of Texas Chancellor’s Council. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey was selected to serve based on vast experience in the oil and gas space and Energy Transfer believes that he provides valuable industry insight as a member of our Board of Directors.
Delinquent Section 16(a) Reports
Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2022, with the exception of one late Form 4 each for Messrs. Wright, Brannon and McReynolds.
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ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Named Executive Officers
Energy Transfer does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of Energy Transfer’s management functions. As a result, the executive officers of our General Partner are Energy Transfer’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. The persons we refer to in this discussion as our “named executive officers” are the following:
•Marshall S. (Mackie) McCrea, III, Co-Chief Executive Officer;
•Thomas E. Long, Co-Chief Executive Officer;
•Dylan A. Bramhall, Executive Vice President and Group Chief Financial Officer;
•Bradford D. Whitehurst, Executive Vice President — Tax and Corporate Initiatives;
•Thomas P. Mason, Executive Vice President — Alternative Energy and President — LNG; and
•James M. Wright, Jr., Executive Vice President, General Counsel and Chief Compliance Officer.
Our Philosophy for Compensation of Executives
In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for its executive officers, including the named executive officers, that provides for a slightly below the median market annual base compensation (i.e., approximately the 30th to 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short- and long-term performance that are both targeted to pay out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its executive officers, including the named executive officers, to the success of the Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit, phantom unit awards or cash restricted unit awards under the Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of executive officers awards, including awards to the named executive officers, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the Partnership and/or the other affiliated partnerships pay to their respective unitholders.
The Partnership has historically granted restricted unit and/or phantom unit awards (“RSUs”) that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. Beginning in 2020, Energy Transfer began granting cash restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. For 2020, the awards to employees were generally split equally between RSUs and CRSUs; for 2021 and 2022, the awards were generally split based on 75% RSUs and 25% CRSUs. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our General Partner places on aligning the interests of its named executive officers with those of Unitholders. While the Partnership utilizes time-based forms of equity awards, the grant date valuation utilizes a modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are a time-vested vehicle.
As discussed below, our compensation committee and/or the compensation committee of the general partner of Sunoco LP, as applicable, all in consultation with our General Partner, are responsible for the compensation policies and compensation level of our executive officers, including the named executive officers of our General Partner. In this discussion, we refer to our compensation committee as the “Energy Transfer Compensation Committee.”
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For a more detailed description of the compensation to the Partnership’s named executive officers, please see “– Compensation Tables” below.
Distributions to Our General Partner
Our General Partner is majority-owned by Mr. Kelcy Warren. We pay quarterly distributions to our General Partner in accordance with our Partnership Agreement with respect to its ownership of its general partner interest as specified in our Partnership Agreement. The cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per-unit distributions equal the per-unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees.
For a more detailed description of the compensation of our named executive officers, please see “– Compensation Tables” below.
Compensation Philosophy
Our compensation programs are structured to achieve the following:
•reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;
•attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships or other peer companies of similar size and in similar lines of business;
•motivate executive officers and key employees to achieve strong financial and operational performance;
•emphasize performance-based, or “at-risk,” compensation; and
•reward individual performance.
Components of Executive Compensation
For the year ended December 31, 2022, the compensation paid to our named executive officers consisted of the following components:
•annual base salary;
•non-equity incentive plan compensation consisting solely of discretionary cash bonuses;
•time-vested RSUs and CRSUs under the equity incentive plan(s);
•payment of distribution equivalent rights (“DERs”) on unvested time-based RSUs under our equity incentive plan;
•vesting of previously issued time-based RSUs issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and
•401(k) plan employer contributions.
Methodology
The Energy Transfer Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The Energy Transfer Compensation Committee also considers individual performance, levels of responsibility, skills and experience.
Periodically, the Energy Transfer Compensation Committee engages a third-party independent compensation consultant to provide a full market competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, in 2021 Meridian Compensation Partners, LLC (“Meridian”) completed an evaluation of the market competitiveness of total compensation levels of a number of officers of the Partnership, including the named executive officers. The Meridian review provided market information with respect to compensation of Partnership executives, including named executive officers during the year ended December 31, 2021. In particular, the review by Meridian was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive
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officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. The Partnership continued to rely on the Meridian review for calendar year 2022.
In conducting its review, Meridian assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of Energy Transfer. The final “peer group” consisted of the core group of peers (i.e. the eight most similar peers in terms of business, revenues, assets and market value as well as competition for talent at the senior management level) and a group of expanded reference companies composed of a broader group of oil and gas companies, including additional integrated, upstream and midstream comparators whose data provided additional market context. As part of the evaluation conducted by Meridian, a determination was made to focus the analysis largely on the core energy industry peers. This decision was based on a determination that the core peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This focus allowed Meridian to report on this specific core peer data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies, while at the same time considering whether the context provided by the expanded group offered additional information that should be considered by the Compensation Committee. The core identified companies were:
Energy Peer Group:
• Conoco Phillips• Marathon Petroleum Corporation
• Enterprise Products Partners, L.P.• Kinder Morgan, Inc.
• Plains All American Pipeline, L.P.• The Williams Companies, Inc.
• Valero Energy Corporation• Phillips 66
The compensation analysis provided by Meridian covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives. In preparing the review materials, Meridian utilized generally accepted compensation principles and gathered data from public disclosures of peer companies, including Form 10-K and proxy data and published survey data from multiple sources that are relevant to Energy Transfer’s core peer group, industry, financial size and operational breadth. The Meridian review process also included significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow Meridian the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.
Following Meridian’s 2021 review, the Energy Transfer Compensation Committee reviewed the information provided, including Meridian’s specific conclusions and recommended considerations for all compensation going forward. The Energy Transfer Compensation Committee considered and reviewed the results of the study performed by Meridian to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Meridian’s conclusions and recommendations. While Meridian found that the Partnership is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments could be considered moving forward to allow the Partnership to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). Certain of Meridian’s suggested adjustments as part of the review were implemented and others were determined to require additional review and consideration.
In addition to the information received as part of Meridian’s review, the Energy Transfer Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third-party surveys, although third-party survey data is not used by the Energy Transfer Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers.
Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e., approximately the 30th to 40th percentile of market) and are determined by the Energy Transfer Compensation Committee after taking into account the recommendations of Mr. Warren.
During the merit review process, the Energy Transfer Compensation Committee considers the recommendations of Mr. Warren, any relevant compensation study data (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. During 2022, the Energy Transfer Compensation Committee approved a 4%
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increase to the base salary of Mr. McCrea to $1,399,320 from the prior level of $1,345,500; a 4% increase to the base salary of Mr. Long to $1,399,320 from the previous level of $1,345,500; an approximately 4% increase to the base salary of Mr. Whitehurst to $640,425 from the previous level of $615,825; and an approximately 4% increase to the base salary of Mr. Mason to $679,695 from the previous level of $653,495.
In connection with his promotion to Group Chief Financial Officer effective November 11, 2022, the Energy Transfer Compensation Committee had previously approved an increase in the annual base salary of Mr. Bramhall to $575,000 from its previous level of $425,000. In connection with his promotion to General Counsel effective November 30, 2022, the Energy Transfer Compensation Committee approved an increase in the annual base salary of Mr. Wright to $550,000 from its previous level of $475,000.
Annual Bonus. In addition to base salary, the Energy Transfer Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Bonus Plan.
The Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Bonus Plan is administered by the Energy Transfer Compensation Committee and the Energy Transfer Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan.
For each calendar year or any other period designated by the Energy Transfer Compensation Committee (the “Performance Period”), the Energy Transfer Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). For purposes of the Adjusted EBITDA Target and the DCF Target established in the Bonus Plan, the measures of Adjusted EBITDA and Distributable Cash Flow are calculated using the same definitions as used in the Partnership’s publicly reported financial information, including the Partnership’s earnings press releases, investor presentations, and annual and quarterly filings on Forms 10-K and 10-Q. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.
While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the Performance Period in light of the contribution of each individual to our profitability and success during such year. The Energy Transfer Compensation Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The Energy Transfer Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.
For Messrs. McCrea and Long, their 2022 bonus pool targets were 160% of their respective annual base earnings, consistent with their previous 2021 targets. For 2022, the Energy Transfer Compensation Committee approved short-term annual cash bonus pool targets for Messrs. Whitehurst, Bramhall and Mason of 130% of their respective annual base earnings, consistent with their previous 2021 targets. In connection with his promotion to General Counsel Mr. Wright’s bonus target for 2022 was increased 130% from its prior level of 115%.
In February 2023, the Energy Transfer Compensation Committee certified 2022 performance results under the Bonus Plan and authorized payment of 120% of the targeted pool. This bonus payout reflected the achievement of 110% of the Adjusted EBITDA Target, 116% of the DCF Target and 94% of, or $47 million under, the Department Budget Target. The Energy Transfer Compensation Committee also used its discretion under the Bonus Plan to exceed the 110% of the achieved pool target
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result and approved a total payout of 120% of the targeted pool amount. The funding of the 120% target was authorized as a result of the significant achievements above the targeted performance metrics.
Based on the approved results, the Energy Transfer Compensation Committee approved a cash bonus relating to the 2022 calendar year to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright in the amounts of $2,635,027, $2,635,027, $700,000, $950,000, $1,040,900 and $762,540, respectively.
Equity Awards. Energy Transfer maintains and operates (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”); the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”); (iv) the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (the “Energy Transfer Plan,” together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “Energy Transfer Incentive Plans”). The Energy Transfer Incentive Plans authorize the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, under each respective plan of RSUs upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the Energy Transfer Incentive Plans. Energy Transfer has generally used time-vested restricted units and/or phantom units as the vehicle for its annual equity awards to eligible employees, including the named executive officers.
In addition, in 2020, Energy Transfer adopted the Energy Transfer LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the Energy Transfer Incentive Plans, awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis, and the CRU Plan is included for purposes of these discussions as an “Energy Transfer Incentive Plan.”
For 2022, the Energy Transfer Compensation Committee established long-term incentive targets for Messrs. McCrea and Long of 900% of their annual base earnings, consistent with their previous targets. In connection with his promotion to Group Chief Financial Officer effective November 11, 2022, the Energy Transfer Compensation Committee established the long-term incentive target for Mr. Bramhall of 500% of his annual base earnings, which was an increase from his previous target of 300% of annual base earnings. For 2022, the Energy Transfer Compensation Committee approved long-term incentive targets for Messrs. Whitehurst, Mason and Wright of 500%, 500% and 300%, respectively, of their respective annual base earnings, consistent with their previous targets.
The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the named executive officers. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by considering Energy Transfer’s modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are time-vested vehicles. For purposes of establishing an initial price, Energy Transfer utilizes a 60 trading-day trailing weighted average price of Energy Transfer common units prior to November 1, 2022. This average trading price is then subject to adjustment when Energy Transfer’s TUR is more than 5% greater or less than that of its identified peer group. If the TUR analysis yields a result that is within 5% percent of its identified peer group, the Energy Transfer Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the named executive officers. If Energy Transfer’s TUR is outside of the 5% deviation, the 60 trading day trailing weighted average will be adjusted up or down to a maximum of 15% from the trailing weighted average price based on Energy Transfer’s performance as compared to the identified group. For 2022, the peer group included the following:
• Enterprise Products Partners, L.P.• Plains All American Pipeline, L.P.
• The Williams Companies, Inc.• MPLX LP
• Kinder Morgan, Inc.
For 2022, the Partnership’s TUR outperformed the identified peer group by approximately 35% based on the average of the identified comparison periods. Consequently, the 2022 long-term incentive base price was decreased to increase the total available restricted pool by the maximum of 15%.
In December 2022, the Energy Transfer Compensation Committee in consultation with Mr. Warren approved grants of RSUs to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 958,950 units, 958,950 units, 175,125 units, 243,750 units, 258,788 units, and 131,250 units, respectively. The Energy Transfer Compensation Committee also approved grants of CRSUs
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to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 319,650 units, 319,650 units, 58,375 units, 81,250 units, 86,262 units and 43,750 units, respectively.
The RSUs granted in 2022 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year. Vesting of the awards is generally subject to continued employment through each specified vesting date. The RSU awards entitle the recipients to receive, with respect to each Energy Transfer unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by Energy Transfer to its common unitholders.
The CRSUs granted in 2022 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the award recipient to receive cash equal to the market value of one Energy Transfer common unit upon vesting. The CRSU do not include rights to DER cash payments.
In approving the grant of such RSUs and CRSUs, including to the named executive officers, the Energy Transfer Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of Energy Transfer’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2022 awards would accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of Energy Transfer as that term is defined under the Energy Transfer Incentive Plans.
For 2020, Mr. McCrea did not receive an award of CRSUs; instead, he received a special one-time time vested cash award of $5,000,000 payable as follows:
•$1,800,000 on December 31, 2020;
•$1,600,000 on July 1, 2021; and
•$1,600,000 on December 5, 2022.
This amount is intended to approximate 50% of Mr. McCrea’s targeted annual equity award and replace the award of CRSUs made to other named executive officers. The last payment of $1,600,000 was made during 2022.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity awards would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the award agreements for the RSUs and CRSUs awarded in 2020, as well as other awards outstanding held by Partnership employees, including the named executive officers, also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards under the Energy Transfer Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section 409(A), which may include a six (6) month delay in the vesting after retirement.
We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we recognizeundergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.
Affiliate and Subsidiary Equity Awards. In addition to his role as an officer for Energy Transfer during 2022, Mr. Bramhall has certain responsibilities for Sunoco LP, including a leadership role for certain shared service functions.
The Sunoco LP Compensation Committee in December 2022 approved a grant of RSUs to Mr. Bramhall of 14,200 restricted units, under the 2018 Sunoco LP Plan. The terms and conditions of the restricted unit to Mr. Bramhall under the 2018 Sunoco LP Plan provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the award would be accelerated in the event of his death or disability, or upon a change in control. The retirement acceleration provisions for this award under the 2018 Sunoco LP Plan are the same as the retirement acceleration provisions under Energy Transfer Incentive Plans with the ability to accelerate at retirement 40% of outstanding unvested awards at age 65 and 50% at age 68.
Special One-Time Awards to Co-Chief Executive Officers. In recognition of their assumption of their new roles as Co-Chief Executive Officers effective January 1, 2021, the Energy Transfer Compensation Committee approved certain one-time awards to Messrs. McCrea and Long.
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Mr. McCrea received a special one-time award of 241,815 RSUs under the Energy Transfer Incentive Plans and a special cash payment of $1,625,000 in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
Mr. Long received a special one-time award of 483,630 RSUs under the Energy Transfer Incentive Plans in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
The RSU awards to Messrs. McCrea and Long were made at the same grant date valuation and vesting schedules used for the annual equity awards described above under “—Equity Awards” section above. These awards were approved by the Energy Transfer Compensation Committee on December 30, 2020 to be effective immediately upon Messrs. McCrea and Long assuming their new roles on January 1, 2021 and are reflected as compensation in 2021 in the Compensation Tables section below.
Unit Ownership Guidelines. In 2021, the Board of Directors of our General Partner adopted an update to the Executive Unit Ownership Guidelines (the “Guidelines”), which sets forth minimum ownership guidelines applicable to certain executives of Energy Transfer with respect to Energy Transfer and Sunoco LP common units, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, (i) the Chief Executive Officer/Co-Chief Executive Officer(s) are expected to own common units having a minimum value of six times base salary; (ii) the Chief Operating Officer, the Chief Financial Officer, the General Counsel and other C-Suite executives expected to own common units having a minimum value of four times their respective base salary; and (iii) Senior Vice Presidents are expected to own common units having a minimum value of two times their respective base salary. In addition to the named executive officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from one to four times their respective base salary.
The Energy Transfer Compensation Committee believes that the ownership of Energy Transfer and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to Energy Transfer’s total unitholder return, aligning the interests of such executives with those of Unitholders, and promoting Energy Transfer’s interest in good corporate governance.
Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines. As of December 31, 2022, all of the named executive officers were compliant with the level required of the Guidelines as of that date.
Covered executives may satisfy the Guidelines through direct ownership of Energy Transfer and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of Energy Transfer and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.
Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.
Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “Energy Transfer 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. During 2020, in response to challenging conditions within the industry, including impacts of the COVID-19 pandemic, Energy Transfer suspended its 401(k) matching contribution from July 1, 2020 through December 31, 2020. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.
The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service. As with the 401(k) matching contributions, Energy Transfer suspended the profit
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sharing contribution from July 1, 2020 through December 31, 2020; however, the profit sharing contributions were reinstated for the full year 2021 and continued throughout 2022.
Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in the Partnership’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.
Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to the named executive officers under the Energy Transfer Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”) provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional information.
In addition, in 2021 the Partnership has also adopted the Partnership Severance Plan and Summary Plan Description effective as of December 1, 2021, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.
Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “Energy Transfer NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the Energy Transfer NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the Energy Transfer NQDC Plan, Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the Energy Transfer NQDC Plan) of Energy Transfer, all Energy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the Energy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement.
Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of Unitholders and our subsidiaries’ unitholders for our long-term performance.
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Tax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation
We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes.
Accounting for Non-Cash Compensation
For non-cash compensation arrangements, we record compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common unitsawards, as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
ETP recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income
For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

3.
ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
2018 Transactions
CDM Contribution Agreement
In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.
In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
Sunoco LP Convenience Store and Real Estate Sale
On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.

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

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

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

sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
2016 Transactions
WMB Merger
On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above. WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.
PennTex Acquisition
On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, ETP purchased PennTex’s remaining outstanding common units in June 2017.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The total purchase price was allocated as follows:
  At November 1, 2016
Total current assets $34
Property, plant and equipment 393
Goodwill(1)
 177
Intangible assets 446
  1,050
   
Total current liabilities 6
Long-term debt, less current maturities 164
Other non-current liabilities 17
Noncontrolling interest 236
  423
Total consideration 627
Cash received 21
Total consideration, net of cash received $606
(1)
None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Sunoco Logistics’ Vitol Acquisition
In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million.
Bakken Financing
In August 2016, ETP and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $2.50 billion was outstanding under this credit facility.
Bayou Bridge
In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system.
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016.
Sunoco LP Acquisitions
In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million, including tax deductible goodwill of $53 million and intangible assets of $56 million. Additionally, during 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $61 million.
In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments.
2015 Transactions
Sunoco LP
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume-weighted average price of Sunoco LP’s common units as of March 20, 2015.
In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.

Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015.
Bakken Pipeline
In March 2015, ETE transferred 46.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.
In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.
Regency Merger
On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 common units of ETP. ETP issued 258.3 million ETP common units to Regency unitholders, including 23.3 million units issued to ETP subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding new ETP Series A Convertible Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.
4.
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Citrus
ETP owns CrossCountry, which owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
FEP
ETP has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. ETP evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. ETP recorded an impairment of its investment in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.

MEP
ETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. ETP evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.
HPC
ETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. ETP evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, ETP recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.
The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2017 and 2016, were as follows:
 December 31,
 2017 2016
Citrus$1,754
 $1,729
FEP121
 101
MEP242
 318
HPC28
 382
Others560
 510
Total$2,705
 $3,040

The following table presents equity in earnings (losses) of unconsolidated affiliates:
 December 31,
Equity in earnings (losses) of unconsolidated affiliates:2017 2016 2015
Citrus$144
 $102
 $97
FEP53
 51
 55
MEP38
 40
 45
HPC(1)
(168) 31
 32
Others77
 46
 47
Total$144
 $270
 $276
(1)
For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented:
 December 31,
 2017 2016
Current assets$206
 $214
Property, plant and equipment, net8,336
 8,726
Other assets43
 181
Total assets$8,585
 $9,121
    
Current liabilities$861
 $816
Non-current liabilities4,492
 4,940
Equity3,232
 3,365
Total liabilities and equity$8,585
 $9,121
 Years Ended December 31,
 2017 2016 2015
Revenue$1,358
 $1,164
 $1,385
Operating income407
 714
 800
Net income145
 384
 470
In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant9 to our consolidated financial statements.

Compensation Committee Interlocks and Insider Participation


5.
NET INCOME PER LIMITED PARTNER UNIT:
Basic net income per limited partner unit is computed by dividing net income, after consideringMr. Steven R. Anderson and Mr. Michael K. Grimm are the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversiononly members of the ETE Series A Convertible Preferred Units,Energy Transfer Compensation Committee. Mr. Ray W. Washburne also served as a member of the Compensation Committee prior to his resignation from the board of directors of our General Partner effective April 1, 2022. During 2022, no member of the Energy Transfer Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. Neither Mr. Grimm nor Mr. Washburne is a former employee of ours or any of our subsidiaries. Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009, as discussed in Note 8. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decreasehis biographical information included in earnings from ETE’s limited partner unit ownership in ETP or Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.“Item 10. Directors, Executive Officers and Corporate Governance.”
A reconciliationReport of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
 Years Ended December 31,
 2017 2016 2015
Income from continuing operations$2,543
 $462
 $1,023
Less: Income (loss) from continuing operations attributable to noncontrolling interest1,583
 (545) (165)
Income from continuing operations, net of noncontrolling interest960
 1,007
 1,188
Less: General Partner’s interest in income from continuing operations2
 3
 3
Less: Convertible Unitholders’ interest in net income from continuing operations38
 8
 —
Less: Class D Unitholder’s interest in income from continuing operations—
 —
 3
Income from continuing operations available to Limited Partners$920
 $996
 $1,182
Basic Income from Continuing Operations per Limited Partner Unit:     
Weighted average limited partner units1,078.2
 1,045.5
 1,062.8
Basic income from continuing operations per Limited Partner unit$0.86
 $0.95
 $1.11
Basic income (loss) from discontinued operations per Limited Partner unit$(0.01) $(0.01) $—
Diluted Income from Continuing Operations per Limited Partner Unit:     
Income from continuing operations available to Limited Partners$920
 $996
 $1,182
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units38
 8
 3
Diluted income from continuing operations available to Limited Partners958
 1,004
 1,185
Weighted average limited partner units1,078.2
 1,045.5
 1,062.8
Dilutive effect of unconverted unit awards and Convertible Units72.6
 33.1
 1.6
Weighted average limited partner units, assuming dilutive effect of unvested unit awards1,150.8
 1,078.6
 1,064.4
Diluted income from continuing operations per Limited Partner unit$0.84
 $0.93
 $1.11
Diluted income (loss) from discontinued operations per Limited Partner unit$(0.01) $(0.01) $—


6.DEBT OBLIGATIONS:
Our debt obligations consist of the following:
 December 31,
 2017 2016
Parent Company Indebtedness:   
7.50% Senior Notes due October 15, 2020$1,187
 $1,187
5.875% Senior Notes due January 15, 20241,150
 1,150
5.50% Senior Notes due June 1, 20271,000
 1,000
4.25% Senior Notes due March 15, 20231,000
 —
ETE Senior Secured Term Loan due December 2, 2019—
 2,190
ETE Senior Secured Term Loan due February 2, 20241,220
 —
ETE Senior Secured Revolving Credit Facility due December 18, 2018—
 875
ETE Senior Secured Revolving Credit Facility due March 24, 20221,188
 —
Unamortized premiums, discounts and fair value adjustments, net(11) (15)
Deferred debt issuance costs(34) (30)
 6,700
 6,357
    
Subsidiary Indebtedness:   
ETP Debt   
6.125% Senior Notes due February 15, 2017—
 400
2.50% Senior Notes due June 15, 2018 (1)
650
 650
6.70% Senior Notes due July 1, 2018 (1)
600
 600
9.70% Senior Notes due March 15, 2019400
 400
9.00% Senior Notes due April 15, 2019450
 450
5.50% Senior Notes due February 15, 2020250
 250
5.75% Senior Notes due September 1, 2020400
 400
4.15% Senior Notes due October 1, 20201,050
 1,050
4.40% Senior Notes due April 1, 2021600
 600
6.50% Senior Notes due July 15, 2021—
 500
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
4.65% Senior Notes due February 15, 2022300
 300
5.875% Senior Notes due March 1, 2022900
 900
5.00% Senior Notes due October 1, 2022700
 700
3.45% Senior Notes due January 15, 2023350
 350
3.60% Senior Notes due February 1, 2023800
 800
5.50% Senior Notes due April 15, 2023—
 700
4.50% Senior Notes due November 1, 2023600
 600
4.90% Senior Notes due February 1, 2024350
 350
7.60% Senior Notes due February 1, 2024277
 277
4.25% Senior Notes due April 1, 2024500
 500
9.00% Debentures due November 1, 202465
 65
4.05% Senior Notes due March 15, 20251,000
 1,000
5.95% Senior Notes due December 1, 2025400
 400
4.75% Senior Notes due January 15, 20261,000
 1,000
3.90% Senior Notes due July 15, 2026550
 550
4.20% Senior Notes due April 15, 2027600
 —
4.00% Senior Notes due October 1, 2027
750
 —
8.25% Senior Notes due November 15, 2029267
 267
4.90% Senior Notes due March 15, 2035500
 500
6.625% Senior Notes due October 15, 2036400
 400
7.50% Senior Notes due July 1, 2038550
 550
6.85% Senior Notes due February 15, 2040250
 250
6.05% Senior Notes due June 1, 2041700
 700
6.50% Senior Notes due February 1, 20421,000
 1,000
6.10% Senior Notes due February 15, 2042300
 300

4.95% Senior Notes due January 15, 2043350
 350
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
5.30% Senior Notes due April 1, 2044700
 700
5.15% Senior Notes due March 15, 20451,000
 1,000
5.35% Senior Notes due May 15, 2045800
 800
6.125% Senior Notes due December 15, 20451,000
 1,000
5.30% Senior Notes due April 15, 2047900
 —
5.40% Senior Notes due October 1, 2047
1,500
 —
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)
50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Unamortized premiums, discounts and fair value adjustments, net33
 66
Deferred debt issuance costs(170) (166)
 29,210
 29,454
    
Transwestern Debt   
5.64% Senior Notes due May 24, 2017—
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Deferred debt issuance costs(1) (1)
 574
 656
    
Panhandle Debt   
6.20% Senior Notes due November 1, 2017—
 300
7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 14, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net28
 50
 813
 1,135
    
Sunoco, Inc. Debt   
5.75% Senior Notes due January 15, 2017—
 400
    
Bakken Project Debt   
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
Deferred debt issuance costs(8) (13)
 2,492
 1,087
PennTex Debt   
PennTex $275 million Revolving Credit Facility due December 2019—
 168
    
Sunoco LP Debt   
5.50% Senior Notes due August 1, 2020600
 600
6.375% Senior Notes due April 1, 2023800
 800
6.25% Senior Notes due April 15, 2021800
 800
Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019765
 1,000
Sunoco LP Term Loan due October 1, 20191,243
 1,243
Lease-related obligations113
 118
Deferred debt issuance costs(34) (47)
 4,287
 4,514

    
Other8
 31
Total debt44,084
 43,802
Less: current maturities of long-term debt413
 1,194
Long-term debt, less current maturities$43,671
 $42,608
(1)
As of December 31, 2017 ETP’s management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
(2)
Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $197 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net:
2018$1,705
20195,512
20203,667
20212,205
20226,540
Thereafter24,652
Total$44,281
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
Notes and Debentures
ETE Senior Notes Offering
In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.Compensation Committee
The senior notes were registeredboard of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of Energy Transfer. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

The Compensation Committee of the
Board of Directors of LE GP, LLC,
general partner of Energy Transfer LP

Steven R. Anderson
Michael K. Grimm
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, (as amended). The Partnership may redeem someas amended, or allthe Exchange Act, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.
146
Compensation Tables
Summary Compensation Table
Name and Principal PositionYearSalary
($)		Bonus
($)
Equity
Awards (1)
($)
Non-Equity
Incentive Plan
Compensation(2)
($)
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
All Other
Compensation (3)
($)
Total
($)
Thomas E. Long2022$1,372,410 $— $14,344,161 $2,635,027 $— $23,917 $18,375,515 
Co-Chief Executive Officer20211,322,750 — 15,224,039 3,156,400 — 27,014 19,730,203 
2020623,077 — 2,781,255 — — 21,603 3,425,935 
Marshall S. (Mackie) McCrea, III (4)
20221,372,410 1,600,000 14,344,161 2,635,027 — 22,794 19,974,392 
Co-Chief Executive Officer20211,322,750 3,225,000 13,734,458 3,156,400 — 22,044 21,460,652 
20201,157,423 1,800,000 4,597,516 — — 18,045 7,572,984 
Dylan A. Bramhall2022429,808 — 3,241,514 700,000 — 16,298 4,387,620 
Group Chief Financial Officer
Bradford D. Whitehurst2022628,125 — 3,646,060 950,000 — 18,510 5,242,695 
Executive Vice President – Tax and Corporate Initiatives2021605,413 — 3,102,694 1,174,000 — 15,760 4,897,867 
2020581,202 — 2,596,850 — — 16,224 3,194,276 
Thomas P. Mason2022666,595 — 3,870,995 1,040,900 21,917 5,600,407 
Executive Vice President – Alternative Energy and President – LNG2021642,445 — 3,279,498 1,252,000 — 22,706 5,196,649 
2020655,680 — 2,609,350 — — 20,007 3,285,037 
James M. Wright, Jr.2022488,808 — 1,963,263 762,540 18,550 19,120 3,252,281 
Executive Vice President, General Counsel and Chief Compliance Officer
(1)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. For Messrs. Long, Bramhall and Whitehurst amounts for one or more periods include equity awards of our subsidiary, Sunoco LP, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the senior notesequity awards. Although the CRSU awards may only be settled in cash, they are based upon the value of Energy Transfer common units and are accounted for as equity awards within these compensation tables.
(2)Energy Transfer maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis.
(3)The amounts reflected for 2022 in this column include (i) matching contributions to the Energy Transfer 401(k) Plan made on behalf of the named executive officers of $15,250 each for Messrs. Long, McCrea, Bramhall, Whitehurst, Mason and Wright, and (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long, McCrea, Whitehurst and Wright, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at anythe time that the unit awards and distribution equivalent rights were originally granted. For 2022, distribution payments in connection with distribution equivalent rights totaled $2,072,643 for Mr. Long, $2,826,685 for Mr. McCrea, $340,120 for Mr. Bramhall, $798,532 for Mr. Whitehurst, $791,164 for Mr. Mason, and $334,890 for Mr. Wright; these amounts include distribution payments on Sunoco LP unit awards for those executives with such unvested awards.
(4)The amounts reflected in the bonus column for Mr. McCrea includes the second payment of Mr. McCrea’s time-vested cash award, which award represented 50% of Mr. McCrea’s total equity award target in 2020. These bonus amounts were paid as follows: $1,800,000 on December 31, 2020, $1,600,000 on July 1, 2021 and $1,600,000 on December 5, 2022. For 2021, the bonus amount reflected above also includes the vesting and payment on February 1, 2021 of a one-time, time-vested cash award of $1,625,000 to Mr. McCrea, which was originally granted in October 2020 in connection with Mr. McCrea’s assumption of his role as Co-Chief Executive Officer.
147
Grants of Plan-Based Awards in 2022
NameGrant DateAll Other Unit Awards: Number of Units
(#)
Grant Date Fair Value of Unit Awards (1)
Energy Transfer Unit Awards:
Thomas E. Long12/12/2022958,950 $11,219,715 
Marshal S. (Mackie) McCrea, III12/12/2022958,950 11,219,715 
Dylan A. Bramhall12/12/2022175,125 2,048,963 
Bradford D. Whitehurst12/12/2022243,750 2,851,875 
Thomas P. Mason12/12/2022258,788 3,027,820 
James M. Wright, Jr.12/12/2022131,250 1,535,625 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long12/12/2022319,650 3,124,446 
Marshal S. (Mackie) McCrea, III12/12/2022319,650 3,124,446 
Dylan A. Bramhall12/12/202258,375 570,591 
Bradford D. Whitehurst12/12/202281,250 794,185 
Thomas P. Mason12/12/202286,262 843,175 
James M. Wright, Jr.12/12/202243,750 427,638 
Sunoco LP Unit Awards:
Dylan A. Bramhall12/12/202214,200 621,960 
(1)We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
148
Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.
Outstanding Equity Awards at 2022 Fiscal Year-End
Name
Grant Date(1)
Unit Awards (1)
Number of Units That Have Not Vested(2)
(#)
Market or Payout Value of Units That Have Not Vested (3)
($)
Energy Transfer Unit Awards:
Thomas E. Long12/12/2022958,950 $11,382,737 
12/16/20211,121,250 13,309,238 
12/30/2020662,180 7,860,077 
12/16/201986,000 1,020,820 
12/18/201854,590 647,983 
10/19/201846,080 546,970 
Marshal S. (Mackie) McCrea, III12/12/2022958,950 11,382,737 
12/16/20211,121,250 13,309,238 
12/30/2020988,165 11,729,519 
12/16/2019272,960 3,240,035 
12/18/2018242,296 2,876,054 
Dylan A. Bramhall12/12/2022175,125 2,078,734 
12/16/202183,400 989,958 
12/30/202037,500 445,125 
12/16/201921,000 249,270 
12/18/201818,000 213,660 
Bradford D. Whitehurst12/12/2022243,750 2,893,313 
12/16/2021228,000 2,706,360 
12/30/2020166,600 1,977,542 
12/16/201960,920 723,120 
12/18/201854,076 641,882 
Thomas P. Mason12/12/2022258,788 3,071,814 
12/16/2021300,300 3,564,561 
12/30/2020234,900 2,788,263 
12/16/201985,920 1,019,870 
12/18/201876,256 905,159 
James M. Wright, Jr.12/12/2022131,250 1,557,938 
12/16/2021131,944 1,566,175 
12/30/202098,755 1,172,222 
12/16/201936,120 428,744 
12/18/201832,060 380,552 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long12/12/2022319,650 3,179,882 
12/16/2021249,167 2,589,238 
12/30/202059,517 646,228 
Marshal S. (Mackie) McCrea, III12/12/2022319,650 3,179,882 
12/16/2021249,167 2,589,241 
Dylan A. Bramhall12/12/202258,375 580,715 
12/16/202118,534 192,598 
12/30/202012,500 135,723 
Bradford D. Whitehurst12/12/202281,250 808,276 
12/16/202150,667 526,511 
12/30/202055,534 602,981 
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Thomas P. Mason12/12/202286,262 858,135 
12/16/202166,734 693,472 
12/30/202078,300 850,172 
James M. Wright, Jr.12/12/202243,750 435,226 
12/16/202129,321 304,692 
12/30/202032,919 357,427 
Sunoco LP Unit Awards:
Thomas E. Long12/30/202027,800 1,198,180 
12/16/20197,800 336,180 
12/19/20187,730 333,163 
Dylan A. Bramhall12/12/202214,200 612,020 
12/16/202113,000 560,300 
12/30/202016,000 689,600 
10/27/202020,000 862,000 
Bradford D. Whitehurst12/16/202116,100 693,910 
12/30/202026,000 1,120,600 
12/16/20197,280 313,768 
12/19/20187,658 330,060 
James M. Wright, Jr.12/19/201832,060 1,381,786 
(1)Certain of these outstanding awards represent subsidiary awards that converted into Energy Transfer awards upon the in connection with restructuring transactions in prior periods.
(2)Energy Transfer and Sunoco LP unit awards outstanding vest as follows:
•at a rate of 60% in December 2025 and 40% in December 2027 for awards granted in December 2022;
•at a rate of 60% in December 2024 and 40% in December 2026 for awards granted in December 2021;
•at a rate of 60% in December 2023 and 40% in December 2025 for awards granted in December 2020;
•100% in December 2024 for the remaining outstanding portion of awards granted in December 2019; and
•100% in December 2023 for the remaining outstanding portion of awards granted in October and December 2018.
Such awards may be settledat the election of the Energy Transfer Compensation Committee in (i) common units of Energy Transfer (subject to the approval of the Energy Transfer Incentive Plans prior to the first vesting date by a majority of Unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the Energy Transfer Incentive Plans) of the Energy Transfer common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or from time(iii) other securities or property in an amount equal to time,the Fair Market Value of Energy Transfer common units that would otherwise be delivered pursuant to the terms of the indenturegrant agreement, or a combination thereof as determined by the Energy Transfer Compensation Committee in its discretion.
Energy Transfer cash restricted unit awards granted in December 2022 vest 1/3 per year in December 2023, 2024 and related indenture supplements related2025. Energy Transfer cash restricted unit awards granted in December 2021 vest 1/2 per year in December 2023 and 2024. The remaining outstanding Energy Transfer cash restricted unit awards granted in December 2020 vest in December 2023.
(3)Market value was computed as the number of unvested awards as of December 31, 2022 multiplied by the closing price of respective common units of Energy Transfer and Sunoco LP. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
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Units Vested in 2022
Unit Awards
NameNumber of Units
Acquired on Vesting
(#)
Value Realized on Vesting
($) (1)
Energy Transfer Unit Awards:
Thomas E. Long177,430 $2,161,097 
Marshall S. (Mackie) McCrea, III624,392 7,605,095 
Dylan A. Bramhall31,500 383,670 
Bradford D. Whitehurst129,758 1,580,452 
Thomas P. Mason183,000 2,228,940 
James M. Wright, Jr.54,180 659,912 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long184,100 2,242,342 
Marshall S. (Mackie) McCrea, III124,583 1,517,421 
Dylan A. Bramhall21,766 265,110 
Bradford D. Whitehurst80,866 984,948 
Thomas P. Mason111,666 1,360,092 
James M. Wright, Jr.47,578 579,500 
Sunoco LP Unit Awards:
Thomas E. Long18,539 812,008 
Bradford D. Whitehurst16,340 715,692 
Thomas P. Mason7,643 334,763 
(1)Amounts presented represent the senior notes. The balancevalue realized upon vesting of these awards, which is payablecalculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon maturity. Interest on the senior notes is paid semi-annually.vesting date.
ETE Senior NotesWe have not issued option awards.
The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially allNonqualified Deferred Compensation Table
A description of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by anykey provisions of the Parent Company’s subsidiaries.Partnership’s deferred compensation plan can be found in the compensation discussion and analysis above.
The covenants related
NameExecutive Contributions in Last FY ($)
Acquired on Vesting
(#)
Registrant Contributions in Last FY ($)
($) (1)
Aggregate Earnings in Last FY ($) (1)
Aggregate Withdrawals/Distributions ($)Aggregate Balance at Last FYE ($)
James M. Wright, Jr.— — 18,550 — 69,745 
(1)Amounts included in the aggregate earnings column above have been included in the change in non-qualified deferred compensation earnings column of the summary compensation table.
Potential Payments Upon a Termination or Change of Control
Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards (including cash restricted unit awards) granted pursuant the Energy Transfer Incentive Plans will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of Energy Transfer or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and salesgeneral partner of Energy Transfer; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the Parent Company’s assets.assets of Energy Transfer in one or more transactions to anyone other than an affiliate of Energy Transfer.
As discussedIn addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the Parent Company’srestricted unit awards, phantom unit awards and cash restricted unit awards under the Energy Transfer Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding senior notes are collateralizedto the named executive officers under the Energy Transfer
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Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the Partnership.
The October 2018 equity award to Mr. Long included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by its interests in certainthe general partner of its subsidiaries. SEC Rule 3-16the applicable partnership issuing the award without “cause.” For purposes of Regulation S-X (“Rule 3-16”) requiresthe awards the term “cause” shall mean: (i) a registrantconviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to file financial statements for eachappeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, whose securities constitute a substantial portion(iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitute substantial portionspartnership or any of its or their affiliates, (vi) material breach of the collateralprovisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.
In addition, the Energy Transfer Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least five years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A). Beginning with awards granted in 2022, the retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration.
Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the Energy Transfer NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the Energy Transfer NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).
CEO Pay Ratio
In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Messrs. Long and McCrea, Co-Chief Executive Officers, and the annual total compensation of our employees.
For the 2022 calendar year, the annual total compensation of Messrs. Long and McCrea, as reported in the Summary Compensation Table of this Item 11 was $18,375,515 and $19,974,392, respectively.
The median total compensation of the employees supporting the Partnership (other than Messrs. Long and McCrea) was $132,358 for 2022, which amount was updated from the 2021 “median employee.”
Based on this information, for 2022 the ratio of the annual total compensation of Messrs. Long and McCrea to the median of the annual total compensation of the employees supporting the Partnership as of December 31, 2022 was approximately 139 to 1 and 151 to 1, respectively.
To identify the median of the annual total compensation of the employees supporting the Partnership, the following steps were taken:
1.It was determined that, as of December 31, 2022, the applicable employee populations consisted of 9,533 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2022 that are required to be included in our employee population for the Parent Company’s outstanding senior notes; accordingly, financial statementsCEO pay ratio evaluation.
2.To identify the “median employee” from our employee population, we compared the total earnings of ETP areour employees as reflected in our payroll records as reported on Form W-2 for 2021, and for 2022, updated the compensation of the “median employee” as reflected in our payroll records as reported on form W-2 for 2022.
3.We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required under Rule 3-16 to be included in the Partnership’s Annual Reportcalculation. We did not make any cost of living adjustments in identifying the “median employee.”
4.Once we identified our median employee, we combined all elements of the employee’s compensation for 2022 resulting in an annual compensation of $132,358 with total base salary of $113,189 The difference between such employee’s total
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earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $12,827) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $6,342 per employee, includes $4,097 per employee on Form 10-Kaverage matching contribution and have been$2,245 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).
5.With respect to Messrs. Long and McCrea, we used the amount reported in the “Total” column of our 2022 Summary Compensation Table under this Item 11.
Director Compensation
In 2022, the compensation arrangements for outside directors included herein.

a $100,000 annual retainer for services on the board. If a director served on the Energy Transfer Audit Committee, such director would receive an annual cash retainer ($15,000 or $25,000 in the case of the chairman). If a director served on the Energy Transfer Compensation Committee, such director would receive an annual cash retainer ($7,500 or $15,000 in the case of the chairman). The fees for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment.
The Parent Company’s interests in ETP GPoutside directors of our General Partner are also constitutes substantial portionsentitled to an annual restricted unit award under the Energy Transfer Incentive Plans equal to an aggregate of $100,000 divided by the closing price of Energy Transfer common units on the date of grant. These Energy Transfer common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the collateralEnergy Transfer common units and is recognized over the vesting period. Distributions are paid during the vesting period.
The compensation paid to the non-employee directors of our General Partner in 2022 is reflected in the following table:
Name
Fees Paid in Cash(1)
($)
Unit Awards(2)
($)
All Other Compensation
($)		Total
($)
Steven R. Anderson$122,500 $100,000 $— $222,500 
Richard D. Brannon125,000 100,000 — 225,000 
Ray C. Davis (3)
100,000 100,000 — 200,000 
Michael K. Grimm130,000 100,000 — 230,000 
James R. Perry100,000 100,000 — 200,000 
Ray W. Washburne (4)
53,750 100,000 — 153,750 
(1)Fees paid in cash are based on amounts paid during the period.
(2)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the Parent Company’s outstanding senior notes. Accordingly, theperiods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. See Note 9 to our consolidated financial statements of ETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. ETP GP does not have substantive operations of its own; rather, ETP GP only owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $28.02 billion“Item 8. Financial Statements and $18.41 billion as of December 31, 2017 and 2016, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, Class H unitholders, Class I unitholders and ETP Preferred Units) of $1.08 billion, $(660) million and $325 millionSupplementary Data” for the years ended December 31, 2017, 2016 and 2015, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations.
ETP’s general partner interest is reflected separately in ETP’s financial statements. As a result, the financial statements of ETP GP would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of ETP GP have been excluded from the Partnership’s Annual Report on Form 10-K.
ETP Senior Notes
The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligations of ETP and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent ofadditional assumptions underlying the value of the assets securing such indebtedness, andequity awards.
(3)Mr. Davis resigned from the ETP senior notes effectively rank junior to all indebtedness and other liabilitiesboard of directors of our existing and future subsidiaries.
Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at anGeneral Partner, effective interest rate of 4.39% at December 31, 2017.2022.
Sunoco LP Private Offering of Senior Notes
On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds(4)Mr. Washburne resigned from the private offering, along with proceeds from the closingboard of the asset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes asdirectors of December 31, 2017, comprised of $800 million in aggregate principal amount of 6.250%senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.
Sunoco LP Senior Notes
Inour General Partner, effective April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.
The 6.25% Senior Notes due 2021 were redeemed on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above.
Term Loans, Credit Facilities and Commercial Paper
ETE Term Loan Facility
On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term

subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements.
Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.
On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.
In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.
ETE Revolving Credit Facility
The Parent Company had a revolver credit agreement which had a scheduled maturity date of December 2, 2018, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The agreement was terminated in connection with entry into the Revolver Credit Agreement, discussed below.
On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.
Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of December 31, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $312 million.

ETP Credit Facilities
On December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).  The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to $6.0 billion under certain conditions. ETP uses the ETP Credit Facilities to provide temporary financing for its growth projects, as well as for general partnership purposes.2022.
As of December 31, 2017, the ETP Five-Year Facility2022, Mr. Anderson had $2.29 billion39,390 unvested Energy Transfer restricted units outstanding, of which $2.01 billion was commercial paper. The amount availableMr. Brannon had 40,645 unvested Energy Transfer restricted units outstanding, Mr. Davis had 39,390 unvested Energy Transfer restricted units outstanding, Mr. Grimm had 47,415 unvested Energy Transfer restricted units outstanding and Mr. Perry had 43,868 unvested Energy Transfer restricted units outstanding.
Non-independent directors do not receive compensation for future borrowings was $1.56 billion after taking into account letters of credit of $150 million. The weighted average interest ratetheir service on the board of our General Partner. Non-independent directors include the executive chairman and the employee directors, as well as Messrs. McReynolds and Ramsey, both of whom recently retired from the Partnership. In connection with his retirement, as previously reported by the Partnership, Mr. Ramsey received accelerated vesting of certain equity awards granted during his employment. The vesting of those equity awards was determined in connection with Mr. Ramsey’s employment and retirement, not his service on the board; therefore, no compensation is reflected in the table above for such vesting.
For 2023, the Board has adopted new compensation arrangement for outside directors, which will raise the annual restricted unit award under the Energy Transfer Incentive Plans equal to an aggregate of $125,000. The awards using the same grant date valuation as is used for annual long-term incentive awards made to Partnership officers, including the named executive officers, through the annual modified total amount outstandingunitholder return analysis. Additionally, moving forward awards to outside directors will be made at the same time such awards are made to the Partnership officers, usually in December of each year.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Equity Compensation Plan Information
The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 20172022:
Plan CategoryNumber of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)		Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)		Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
Equity compensation plans approved by security holders— $— — 
Equity compensation plans not approved by security holders37,713,968 — 3,578,984 
Total37,713,968 $— 3,578,984 
Energy Transfer LP Units
The following table sets forth certain information as of February 10, 2023, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.
Beneficially Owned (2)
Percent of Class
Name and Address of
Beneficial Owner (1)
Common Units
Class A
Units(3)
Common UnitsClass A Units
Kelcy L. Warren (4)
287,799,984 765,993,4299.3 %100.0 %
Thomas E. Long773,628 — *N/A
Marshall S. (Mackie) McCrea, III3,085,646 — *N/A
Dylan A. Bramhall109,943 — *N/A
Thomas P. Mason744,056 — *N/A
Bradford D. Whitehurst (5)
538,709 — *N/A
James M. Wright, Jr.221,266 — *N/A
Steven R. Anderson (6)
1,555,163 — *N/A
Richard D. Brannon (7)
696,071 — *N/A
Michael K. Grimm (8)
688,941 — *N/A
John W. McReynolds (9)
30,225,200 — *N/A
James R. Perry126,027 — *N/A
Matthew S. Ramsey1,121,845 — *N/A
Blackstone Holdings I/II GP L.L.C. (10)
160,737,127 — 5.2 %N/A
All Directors and Executive Officers as a group (14 persons)327,802,291 765,993,429 10.6 %100.0 %
*    Less than 1%
(1)The address for all listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.
(2)Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power
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unless otherwise noted. The beneficial ownership of each listed person is based on 3,094,593,760 common units outstanding in the aggregate as of February 10, 2023.
(3)The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units and are not entitled to distributions and otherwise have no economic attributes. The Energy Transfer Class A Units are not convertible into, or exchangeable for, Partnership common units. Under the terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to the general partner additional Energy Transfer Class A Units such that Mr. Warren, through his majority ownership of our general partner, maintains the approximately 20% voting percentage in the Partnership represented by such Energy Transfer Class A Units equivalent to such Energy Transfer Class A Unit voting interest prior to such issuance of additional common units. This provision of the Energy Transfer Class A Units shall terminate at such time as Mr. Warren ceases to be an officer or director of our general partner, provided that all Energy Transfer Class A Units outstanding at such time shall be unchanged and remain outstanding. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(4)Includes 120,385,650 common units held by Kelcy Warren Partners, L.P. and 10,224,429 common units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 100,577,803 common units held by Kelcy Warren Partners III, LLC formerly known as Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 common units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also includes 601,076 common units and 765,933,429 Energy Transfer Class A Units held by LE GP, LLC. Mr. Warren may be deemed to own common units and Energy Transfer Class A Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. Mr. Warren disclaims beneficial ownership of common units and Energy Transfer Class A Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 104,166 common units held by Mr. Warren’s spouse. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(5)Includes 297,617 common units held by Mr. Whitehurst in a margin account.
(6)Includes 1,544,558 common units held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee.
(7)Includes 580,000 common units held by B4 Capital Investments, LP, a limited partnership of which a limited liability company owned by Mr. Brannon and his wife is the sole general partner and of which Mr. Brannon and his wife are the sole limited partners.
(8)Includes 530,173 common units held Grimm Family Limited Partnership, a limited partnership of which a limited liability company owned by Mr. Grimm is the sole general partner.
(9)Includes 17,445,608 common units held by McReynolds Energy Partners L.P. and 12,142,593 common units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of common units owned by such limited partnerships other than to the extent of his interest in such entities.
(10)This information is based on a Schedule 13G filed on February 9, 2023 by Blackstone Holdings I/II GP L.L.C. on behalf of itself and Blackstone Inc., Blackstone Group Management L.L.C., and Stephen A. Schwarzman, each of which reported sole voting and dispositive power with respect to 160,737,127 Energy Transfer Common Units. The sole member of Blackstone Holdings I/II GP L.L.C. is Blackstone Inc. The sole holder of the Series II preferred stock of Blackstone Inc. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. The address for each reporting person identified in the February 9, 2023 filing was 2.48%.345 Park Avenue, New York, NY 10154.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Partnership’s principal sources of cash flow are derived from cash flows from the operations of its subsidiaries, including its direct and indirect investments in the limited partner and general partner interests in Sunoco LP and USAC, both of which are limited partnerships engaged in energy-related services.
In making its director independence determination, the Board considered business arrangements involving a director who owns equity interest in, and is the CEO of, a company that owns working interests in oil and gas wells, and affiliates of the Partnership who made nominal payments to that company. None of the arrangements involved payments to the company of more than $1 million in any of the past three fiscal years and the Board determined that the relationship did not impact the director’s independence.
For a discussion of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”
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As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of December 31, 2017,directors makes the ETP 364-Day Facility had $50 million outstanding,determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The Partnership Agreement of Energy Transfer provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to Energy Transfer, approved by all the amount available for future borrowings was $950 million. The weighted average interest rate onpartners of Energy Transfer and not a breach by the total amount outstanding asGeneral Partner or its Board of December 31, 2017 was 5.00%Directors of any duties they may owe Energy Transfer or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
ETLP Credit FacilityAdditional information on our related party transactions is included in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The ETLP Credit Facility allowedfollowing sets forth fees billed by Grant Thornton LLP for borrowingsthe audit of upour annual financial statements and other services rendered (dollars in millions):
 Years Ended December 31,
 20222021
Audit fees (1)
$10.8 $10.7 
Audit-related fees(2)
— 0.3 
Total$10.8 $11.0 
(1)Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to $3.75 billionthe audit of our internal control over financial reporting.
(2)Includes fees for financial due diligence related to acquisitions.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and was usedfinancial practices. The Audit Committee has the responsibility to provide temporary financingselect, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our growth projects,principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2022 and 2021 were pre-approved by the Audit Committee in accordance with this policy.
The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for general partnership purposes. This facility was repaid and terminated concurrentsole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the establishmentexternal auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
•the auditors’ internal quality-control procedures;
•any material issues raised by the most recent internal quality-control review, or peer review, of the ETP Credit Facilities on December 1, 2017.external auditors;
Sunoco Logistics Credit Facilities
ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with •the establishmentindependence of the ETP Credit Facilities on December 1, 2017.external auditors;
In December 2016, Sunoco Logistics entered into an agreement•the aggregate fees billed by our external auditors for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earliereach of the occurrenceprevious two years; and
•the rotation of the Sunoco Logistics Merger or in December 2017, with a total lending capacitylead partner.
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Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipateddex to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2017, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%.Financial Statements
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.
Sunoco LP Term Loan
Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of December 31, 2017, the balance on the term loan was $1.24 billion.
The Sunoco LP term loan was repaid in full and terminated on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay

incremental interest owed under the revolving credit facility. As of December 31, 2017,2022, the Sunoco LP credit facilityCredit Facility had $9$900 million of outstanding borrowings and $7 million in standby letters of credit.credit and matures in July 2023. The amount available for future borrowings on the revolverwas $593 million at December 31, 20172022. The weighted average interest rate on the total amount outstanding as of December 31, 2022 was $726 million.6.17%.
On October 16, 2017, Sunoco LP entered into the Fifth Amendment to theUSAC Credit Agreement with the lenders party theretoFacility
As of December 31, 2022, USAC had $646 million of outstanding borrowings and Bank of America, N.A., in its capacity as a letterno outstanding letters of credit issuer,under the credit agreement. As of December 31, 2022, USAC had $954 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $333 million. The weighted average interest rate on the total amount outstanding as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.December 31, 2022 was 6.84%.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.
The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:
Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company to Consolidated EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and
Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.
Covenants Related to ETP
The agreements relating to the ETP senior notesSenior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The ETPFive-Year Credit FacilitiesFacility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
•incur indebtedness;
•grant liens;
•enter into mergers;
•dispose of assets;
•make certain investments;
•make Distributions (as defined in the ETPFive-Year Credit Facilities)Facility) during certain Defaults (as defined in the ETPFive-Year Credit Facilities)Facility) and during any Event of Default (as defined in the ETPFive-Year Credit Facilities)Facility);
•engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
•engage in transactions with affiliates; and
•enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Credit Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125%
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The ETPFive-Year Credit Facilities containFacility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETPFive-Year Credit FacilitiesFacility also limitlimits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements,

agreement, of 5.05.00 to 1,1.00, which can generally be increased to 5.55.50 to 11.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.963.32 to 11.00 at December 31, 2017,2022, as calculated in accordance with the credit agreements.agreement.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.
Covenants Related to Transwestern
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.

Covenants Related to Sunoco LP
The Sunoco LP Credit Facilities containFacility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LPLP’s Credit Facilities  requireFacility requires Sunoco LP to maintain a specified net leverage ratio (as defined therein)and interest coverage ratio.
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:
•grant liens;
•make certain loans or investments;
•incur additional indebtedness or guarantee other indebtedness;
•enter into transactions with affiliates;
•merge or consolidate;
•sell our assets; and
•make certain acquisitions.
The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:
•a minimum EBITDA to interest coverage ratio;
•a ratio of not more than (a) astotal secured indebtedness to EBITDA within a specified range; and
•a maximum funded debt to EBITDA ratio.
Covenants Related to the HFOTCO Tax Exempt Notes
The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the last day of each fiscal quarter through December 31, 2017, 6.75bondholders, taking actions to 1.0, (b) as of March 31, 2018, 6.5remove the trustee, making certain amendments to 1.0, (c) as of June 30, 2018, 6.25the bond documents, and taking actions or omitting to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (intake actions that adversely impact the casetax exempt status of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities.  Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released.IKE Bonds.
Compliance With Ourwith our Covenants
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.
We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.2022.
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7.ETP CONVERTIBLE PREFERRED UNITS:
The ETP Convertible Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The ETP Convertible Preferred Units are entitledIndex to a preferential quarterly cash distribution of $0.445 per ETP Preferred Unit if outstanding on the record dates of ETP’s common unit distributions. In January 2017, ETP repurchasedFinancial Statements
Cash Distributions
Cash Distributions Paid by Energy Transfer
Under its Partnership Agreement, Energy Transfer will distribute all of its 1.9 million outstanding ETP Convertible Preferred Units for cash in the aggregate amount of $53 million.
8.EQUITY:
Limited Partner Units
Limited partner interestsAvailable Cash, as defined in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”
As of December 31, 2017, there were issued and outstanding 1.08 billion Common Units representing an aggregate 94.38% limited partner interest in the Partnership.
Our Partnership Agreement, contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

Common Units
The change in ETE Common Units during the years ended December 31, 2017, 2016 and 2015 was as follows:
 Years Ended December 31,
 2017 2016 2015
Number of Common Units, beginning of period1,046.9
 1,044.8
 1,077.5
Conversion of Class D Units to ETE Common Units—
 —
 0.9
Repurchase of common units under buyback program—
 —
 (33.6)
Issuance of common units32.2
 2.1
 —
Number of Common Units, end of period1,079.1
 1,046.9
 1,044.8
ETE Equity Distribution Agreement
In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017.
ETE Series A Convertible Preferred Units
 Years Ended December 31,
 2017 2016 2015
Number of Series A Convertible Preferred Units, beginning of period329.3
 —
 —
Issuance of Series A Convertible Preferred Units—
 329.3
 —
Number of Series A Convertible Preferred Units, end of period329.3
 329.3
 —
On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). Atwithin 50 days following the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, madefiscal quarter. Available Cash generally means, with respect to any quarter, during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common unitsall cash on hand at the end of such quarter less the plan period. The Convertible Units had $450 million carrying value asamount of December 31, 2017.
ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s

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

During the year ended December 31, 2017, ETP issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of ETP’s Common Units remained available to be issued under ETP’s currently effective equity distribution agreement.
ETP’s Equity Incentive Plan Activity
ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.
ETP’s Distribution Reinvestment Program
ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan.
During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.
As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement.
August 2017 Units Offering
In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
ETP Class E Units
There are currently 8.9 million ETP Class E Units outstanding, all of which are currently owned by HHI. The ETP Class E Units generally do not have any voting rights. The ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the ETP Class E Units at a future date.
ETP Class G Units
There are currently 90.7 million ETP Class G Units outstanding, all of which are held by wholly-owned subsidiaries of ETP. The ETP Class G Units generally do not have any voting rights. The ETP Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class G Unit per year. Allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements.
ETP Class H Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.

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

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

its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.
Parent Company Quarterly Distributions of Available Cash
Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.
Our distributions declared and paid with respect to ourEnergy Transfer common units for the periods presented were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2014February 6, 2015February 19, 20150.2250
March 31, 2015May 8, 2015May 19, 20150.2450
June 30, 2015August 6, 2015August 19, 20150.2650
September 30, 2015November 5, 2015November 19, 20150.2850
December 31, 2015February 4, 2016February 19, 20160.2850
March 31, 2016 (1)
May 6, 2016May 19, 20160.2850
June 30, 2016 (1)
August 8, 2016August 19, 20160.2850
September 30, 2016 (1)
November 7, 2016November 18, 20160.2850
December 31, 2016 (1)
February 7, 2017February 21, 20170.2850
March 31, 2017 (1)
May 10, 2017May 19, 20170.2850
June 30, 2017 (1)
August 7, 2017August 21, 20170.2850
September 30, 2017 (1)
November 7, 2017November 20, 20170.2950
December 31, 2017 (1)
February 8, 2018February 20, 20180.3050
(1)
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended
December 31, 2020February 8, 2021February 19, 2021$0.1525 
March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional information below.2021May 11, 2021May 19, 20210.1525 
June 30, 2021August 6, 2021August 19, 20210.1525 
September 30, 2021November 5, 2021November 19, 20210.1525 
December 31, 2021February 8, 2022February 18, 20220.1750 
March 31, 2022May 9, 2022May 19, 20220.2000 
June 30, 2022August 8, 2022August 19, 20220.2300 
September 30, 2022November 4, 2022November 21, 20220.2650 
December 31, 2022February 7, 2023February 21, 20230.3050 
OurThe total amounts of distributions declared and paid with respect to our Convertible Unit during the years ended December 31, 2016periods presented (all from Available Cash from Energy Transfer’s operating surplus and 2017are shown in the period to which they relate) are as follows:
 Years Ended December 31,
 20222021
Limited Partners$3,089 $1,777 
General Partner interest3 2 
Total Energy Transfer distributions$3,092 $1,779 
Energy Transfer Preferred Unit Distributions
As discussed in Note 8 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data”, in connection with the Rollup Mergers, ETO’s outstanding preferred units were converted into Energy Transfer Preferred Units on April 1, 2021.
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Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and Series H preferred units declared and/or paid by Energy Transfer were as follows:
Period EndedRecord DatePayment Date
Series A (1)
Series B (1)
Series CSeries DSeries E
Series F (1)
Series G (1)
Series H (1)
March 31, 2021May 3, 2021May 17, 2021$—$—$0.4609$0.4766$0.4750$33.75$35.63$—
June 30, 2021August 2, 2021August 16, 202131.2533.130.46090.47660.4750———
September 30, 2021November 1, 2021November 15, 2021——0.46090.47660.475033.7535.6327.08*
December 31, 2021February 1, 2022February 15, 202231.2533.130.46090.47660.4750———
March 31, 2022May 2, 2022May 16, 2022——0.46090.47660.475033.7535.6332.50
June 30, 2022August 1, 2022August 15, 202231.2533.130.46090.47660.4750———
September 30, 2022November 1, 2022November 15, 2022——0.46090.47660.475033.7535.6332.50
December 31, 2022February 1, 2023February 15, 202331.2533.130.46090.47660.4750———
Quarter Ended          Record Date Payment Date  Rate
March 31, 2016 May 6, 2016 May 19, 2016 $0.1100
June 30, 2016 August 8, 2016 August 19, 2016 0.1100
September 30, 2016 November 7, 2016 November 18, 2016 0.1100
December 31, 2016 February 7, 2017 February 21, 2017 0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
December 31, 2017 February 8, 2018 February 20, 2018 0.1100
*    Represents prorated initial distribution.
ETP’s Quarterly Distributions of Available Cash
Under ETP’s limited partnership agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves(1)    Series A, Series B, Series F, Series G and payment of fees and expenses, including payments to the general partner.

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

In connection with previous transactions, we have agreed to relinquish its right to the following amounts of incentive distributions in future periods:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared and paid by ETP to the Series A and Series B preferred unitholders were as follows:
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
units will be paid quarterly beginning after February 15, 2023 and February 15, 2028, respectively
Sunoco LP QuarterlyCash Distributions
Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Available CashSunoco LP’s incentive distribution rights. As of December 31, 2022, Sunoco LP had approximately 84.1 million common units outstanding.
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.
Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target AmountCommon UnitholdersHolder of IDRs
Minimum Quarterly Distribution $0.4375100%—%
First Target Distribution$0.4375 to $0.503125100%—%
Second Target Distribution$0.503125 to $0.54687585%15%
Third Target Distribution$0.546875 to $0.65625075%25%
ThereafterAbove $0.65625050%50%

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Distributions on Sunoco LP’s units declared andand/or paid by Sunoco LP for the periods presented were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2014February 17, 2015February 27, 20150.6000
March 31, 2015May 19, 2015May 29, 20150.6450
June 30, 2015August 18, 2015August 28, 20150.6934
September 30, 2015November 17, 2015November 27, 20150.7454
December 31, 2015February 5, 2016February 16, 20160.8013
March 31, 2016May 6, 2016May 16, 20160.8173
June 30, 2016August 5, 2016August 15, 20160.8255
September 30, 2016November 7, 2016November 15, 20160.8255
December 31, 2016February 13, 2017February 21, 20170.8255
March 31, 2017May 9, 2017May 16, 20170.8255
June 30, 2017August 7, 2017August 15, 20170.8255
September 30, 2017November 7, 2017November 14, 20170.8255
December 31, 2017February 06, 2018February 14, 20180.8255
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
 December 31,
 2017 2016
Available-for-sale securities$8
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain (loss) related to pensions and other postretirement benefits(5) 7
Investments in unconsolidated affiliates, net5
 4
Subtotal3
 8
Amounts attributable to noncontrolling interest(3) (8)
Total AOCI included in partners’ capital, net of tax$—
 $—
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):
 December 31,
 2017 2016
Available-for-sale securities$(2) $(2)
Foreign currency translation adjustment3
 3
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$4
 $1
9.UNIT-BASED COMPENSATION PLANS:
December 31, 2020February 8, 2021February 19, 2021$0.8255 
March 31, 2021May 11, 2021May 19, 20210.8255 
June 30, 2021August 6, 2021August 19, 20210.8255 
September 30, 2021November 5, 2021November 19, 20210.8255 
December 31, 2021February 8, 2022February 18, 20220.8255 
March 31, 2022May 9, 2022May 19, 20220.8255 
June 30, 2022August 8, 2022August 19, 20220.8255 
September 30, 2022November 4, 2022November 18, 20220.8255 
December 31, 2022February 7, 2023February 21, 20230.8255 
We, ETP andThe total amount of distributions to the Partnership from Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.
ETE Long-Term Incentive Plan
The Board of Directors or the Compensation Committee of the board of directors of our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantomperiods presented below is as follows:

Years Ended December 31,
20222021
Distributions from Sunoco LP
Limited Partner interests$94 $94 
General Partner interest and IDRs72 71 
Total distributions from Sunoco LP$166 $165 
units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12.0USAC Cash Distributions
Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2017, 10.82022, USAC had approximately 98.2 million common units remain availableoutstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.
Distributions on USAC’s units declared and/or paid by USAC were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2020January 25, 2021February 5, 2021$0.5250 
March 31, 2021April 26, 2021May 7, 20210.5250 
June 30, 2021July 26, 2021August 6, 20210.5250 
September 30, 2021October 25, 2021November 5, 20210.5250 
December 31, 2021January 24, 2022February 4, 20220.5250 
March 31, 2022April 25, 2022May 6, 20220.5250 
June 30, 2022July 25, 2022August 5, 20220.5250 
September 30, 2022October 24, 2022November 4, 20220.5250 
December 31, 2022January 23, 2023February 3, 20230.5250 
The total amount of distributions to be awarded under the plan.Partnership from USAC for the periods presented below is as follows:
During
Years Ended December 31,
20222021
Distributions from USAC
Limited Partner interests$97 $97 
Total distributions from USAC$97 $97 
Critical Accounting Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives,
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but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results are estimated using volume estimates and market prices for our intrastate transportation and storage segment, our midstream segment, and our NGL and refined products transportation and services segment. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 2017, 1.2 million ETE unit awards were granted2022 represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, ETE employees andthe timing of certain employees of ETP and 15,648 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grantsforecasted transactions that vest 60% in three years and 40% in five years and do not entitleare hedged, the holders to receive distributions during the vesting period.
During the year ended December 31, 2017 and 2016, a total of 2,018 and 28,648 ETE Common Units vested, with a total fair value of $39 thousandderivative instruments, useful lives for depreciation, depletion and $205 thousand, respectively, asamortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Fair Value Estimates in Business Combination Accounting and Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates. Business combination accounting and quantitative impairment testing are required from time to time due to the occurrence of events, changes in circumstances, or annual testing requirements. For business combinations, assets and liabilities are required to be recorded at estimated fair value in connection with the initial recognition of the vesting date. As of December 31, 2017, a total of 1,251,002 restricted units remain outstanding,transaction. For impairment testing, long-lived assets are required to be tested for which we expect to recognize a total of $21 millionrecoverability whenever events or changes in compensation over a weighted average period of 3.5 years.
Subsidiary Unit-Based Compensation Plans
Each of ETP and Sunoco LP has granted restricted or phantom unit awards (collectively,circumstances indicate that the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common unitscarrying amount of the respective subsidiary. In some cases, atasset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the discretionrelated asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. An impairment loss should be recognized only if the carrying amount of the respective subsidiary’s compensation committee,asset/goodwill is not recoverable and exceeds its fair value. Calculating the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.
The following table summarizes the activity of the Subsidiary Unit Awards:
 ETP Sunoco LP
 
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
 
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
Unvested awards as of December 31, 20169.4
 $27.68
 2.0
 $34.43
Legacy Sunoco Logistics unvested awards as of December 31, 20163.2
 28.57
 —
 —
Awards granted4.9
 17.69
 0.2
 28.31
Awards vested(2.3) 34.22
 (0.3) 45.48
Awards forfeited(1.1) 25.03
 (0.2) 34.71
Unvested awards as of December 31, 201714.1
 23.18
 1.7
 31.89
Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31:       
2017  $17.69
   $28.31
2016  23.82
   26.95
2015  23.47
   40.63
The total fair value of Subsidiary Unit Awards vestedassets or reporting units in connection with business combination accounting or impairment testing requires management to make several estimates, assumptions and judgements, and in some circumstances management may also utilize third-party specialists to assist and advise on those calculations.
In order to allocate the purchase price in a business combination or to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of commodities, our ability to negotiate favorable sales agreements, the risks that exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.
The Partnership determines the fair value of its assets and/or reporting units using a discounted cash flow method, the guideline company method, the reproduction and replacement methods, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our business combination accounting and impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s
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projected EBITDA and then averaging that estimate with similar historical calculations using a multi-year average. In addition, the Partnership estimates a reasonable control premium, when appropriate, representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. Under the reproduction and replacement methods, the Partnership determines the fair value of assets based on the estimated installation, engineering, and set-up costs related to the asset; these methods require the use of trend factors, such as inflation indices.
One key assumption in these fair value calculations is management’s estimate of future cash flows and EBITDA. In accounting for a business combination, these estimates are generally based on the forecasts that were used to analyze the deal economics. For impairment testing, these estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for business combination accounting and impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in changes to the fair value estimates used in business combination accounting, which could significantly impact results of operations in a period subsequent to the business combination, depending on multiple factors, including the timing of such changes. In the case of impairment testing, such changes could result in additional impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments.
In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also result in an impairment or impact the magnitude of an impairment.
During the years ended December 31, 2017, 2016,2022, 2021 and 2015 was $40 million, $40 million,2020, the Partnership recorded total assets of $1.38 billion, $8.58 billion and $57$12 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years.connection with business combinations.

10.INCOME TAXES:
As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
 Years Ended December 31,
 2017 2016 2015
Current expense (benefit):     
Federal$54
 $(47) $(308)
State(16) (34) (54)
Total38
 (81) (362)
Deferred expense (benefit):     
Federal(2,055) (189) 268
State184
 12
 (29)
Total(1,871) (177) 239
Total income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)
Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations forDuring the years ended December 31, 2017, 20162022, 2021 and 20152020, the Partnership recorded impairments totaling $386 million, $21 million and $3.01 billion, respectively, including $129 million in impairments in unconsolidated affiliates in 2020, and $5 million and $66 million of long-lived asset impairments in 2021 and 2020, respectively. Additional information on the impairments recorded during these periods is as follows:available in “Item 8. Financial Statements and Supplementary Data.”
 2017 2016 2015
Income tax expense (benefit) at United States statutory rate of 35 percent$248
 $71
 $316
Increase (reduction) in income taxes resulting from:     
Partnership earnings not subject to tax(477) (576) (355)
Goodwill impairment207
 278
 —
State tax, net of federal tax benefit124
 (10) (29)
Dividend received deduction(14) (15) (22)
Federal rate change(1,812) —
 —
Audit settlement—
 —
 (7)
Change in tax status of subsidiary(124) —
 —
Other15
 (6) (26)
Income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal componentsManagement does not believe that any of the deferred taxPartnership’s goodwill balances, long-lived assets (liabilities) as follows:
 December 31,
 2017 2016
Deferred income tax assets:   
Net operating losses and alternative minimum tax credit$683
 $472
Pension and other postretirement benefits21
 30
Long-term debt14
 32
Other191
 182
Total deferred income tax assets909
 716
Valuation allowance(189) (118)
Net deferred income tax assets720
 598
    
Deferred income tax liabilities:   
Property, plant and equipment(1,036) (1,633)
Investments in unconsolidated affiliates(2,726) (3,789)
Trademarks(173) (273)
Other(100) (15)
Total deferred income tax liabilities(4,035) (5,710)
Net deferred income taxes$(3,315) $(5,112)
The table below providesor investments in unconsolidated affiliates is currently at significant risk of a rollforwardmaterial impairment; however, of the net deferred income tax liability as follows:
 December 31,
 2017 2016
Net deferred income tax liability, beginning of year$(5,112) $(4,590)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)—
 (460)
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)—
 (243)
Tax provision, including provision from discontinued operations1,825
 201
Other(28) (20)
Net deferred income tax liability$(3,315) $(5,112)
ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits$2.57 billion of $403 million, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant togoodwill on the Tax Cuts and Jobs Act. Our corporate subsidiaries have net operating loss carryforward benefits of $274 million, $217 million net of federal tax, which expire between January 1, 2018 and 2037. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.

The following table sets forth the changes in unrecognized tax benefits:
 Years Ended December 31,
 2017 2016 2015
Balance at beginning of year$615
 $610
 $440
Additions attributable to tax positions taken in the current year—
 8
 178
Additions attributable to tax positions taken in prior years28
 18
 —
Reduction attributable to tax positions taken in prior years(25) (20) —
Lapse of statute(9) (1) (8)
Balance at end of year$609
 $615
 $610
As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of tax.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in its litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in thePartnership’s consolidated balance sheet as of December 31, 2017.2022, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.
In December 2015,Estimated Useful Lives of Long-Lived Assets. Depreciation and amortization of long-lived assets is provided using the Pennsylvania Commonwealth Court determinedstraight-line method based on their estimated useful lives. Changes in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clauseestimated useful lives of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax benefits) against the receivable.
In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.
Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.
ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.81 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will notcould have a material adverse effect on its financial position orour results of operation. The Partnership’s results of operations have not been significantly impacted by changes in the estimated useful lives of our long-lived assets during the periods presented, and we do not anticipate any such significant changes in the future. However, changes in facts and circumstances could cause us to change the estimated useful lives of the assets, which could significantly impact the Partnership’s results of operations. Additional information on our accounting policies and the estimated useful lives associated with our long-lived assets is available in “Item 8. Financial Statements and Supplementary Data.”
ETP’s joint venture agreements require that they fund their proportionate share of capital contributionsLegal and Regulatory Matters. We are subject to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
  Years Ended December 31,
  2017 2016 2015
Rental expense(1)
 $196
 $187
 $281
Less: Sublease rental income (25) (26) (26)
Rental expense, net $171
 $161
 $255
(1)
Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively.

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

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing.
While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
complaints. As of December 31, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania2022 and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is

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

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

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

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.
Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2017 and 2016,2021, accruals of approximately $33$200 million and $77$144 million, respectively, were reflected onin our consolidated balance sheets related to these contingent obligations. As new
For more information becomes available, our estimates may change. The impact of these changes may have a significant effect on our resultslitigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.
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The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts priorIndex to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.Financial Statements
No amounts have been recorded in our December 31, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million

for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
Environmental Remediation
Our subsidiaries are responsible Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at certainidentified sites including the following:
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Legacy sites related to Sunoco, Inc.where an assessment has indicated that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediationcleanup costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, weThe 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 not ableused to estimate possible losses or a rangeidentify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of possible losses in excess of amounts accrued. Except for matters discussed above, we do notoccurrence and reasonably estimable. We have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
 December 31,
 2017 2016
Current$35
 $26
Non-current337
 318
Total environmental liabilities$372
 $344

In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
DuringIn general, each remediation site/issue is evaluated individually based upon information available for the years endedsite/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. The Partnership’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $282 million and $293 million in environmental accruals as of December 31, 20172022 and 2016,2021, respectively.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.
Deferred Income Taxes. Energy Transfer recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal excess business interest expense carryforwards totaling $603 million have been included in Energy Transfer’s consolidated balance sheet as of December 31, 2022. The state NOL carryforward benefits of $104 million ($82 million net of federal benefit) began expiring in 2023 with a substantial portion expiring between 2033 and 2039. Energy Transfer’s corporate subsidiaries have federal NOLs of $2.4 billion ($496 million in benefits) of which $645 million will expire between 2036 and 2037. A total of $341 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. We have determined that a valuation allowance totaling $4 million ($3 million net of federal income tax effects) is required for state NOLs as of December 31, 2022 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. A separate valuation allowance of $15 million is attributable to foreign tax credits. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded $32 million and $43 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. enteredasset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period.  On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations.  To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relateadjustment to the timedeferred tax asset will increase income in the period such determination is made.
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Forward-Looking Statements
This annual report contains various forward-looking statements and information that Sunoco, Inc. operated the refinery.  Specifically, EPA has claimedare based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, andexpectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect theresuch expectations will prove to be correct. Forward-looking statements are subject to a material impactvariety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
•the ability of our subsidiaries to itsmake cash distributions to us, which is dependent on their results of operations, cash flows orand financial position.condition;
Our pipeline operations are subject•the actual amount of cash distributions by our subsidiaries to regulation by us;
•the United States Departmentvolumes transported on our subsidiaries’ pipelines and gathering systems;
•the level of Transportation under throughput in our subsidiaries’ processing and treating facilities;
•the PHMSA, pursuant to whichfees our subsidiaries charge and the PHMSA has established requirements relatingmargins they realize for their gathering, treating, processing, storage and transportation services;
•the prices and market demand for, and the relationship between, natural gas and NGLs;
•energy prices generally;
•impacts of world health events, including the COVID-19 pandemic;
•the prices of natural gas and NGLs compared to the design, installation, testing, construction, operation, replacementprice of alternative and managementcompeting fuels;
•the general level of petroleum product demand and the availability and price of NGL supplies;
•the level of domestic oil, natural gas and NGL production;
•the availability of imported oil, natural gas and NGLs;
•actions taken by foreign oil and gas producing nations;
•the political and economic stability of petroleum producing nations;
•the effect of weather conditions on demand for oil, natural gas and NGLs;
•availability of local, intrastate and interstate transportation systems;
•the continued ability to find and contract for new sources of natural gas supply;
•availability and marketing of competitive fuels;
•the impact of energy conservation efforts;
•energy efficiencies and technological trends;
•governmental regulation and taxation;
•changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•competition from other midstream companies and interstate pipeline facilities. Moreover,companies;
•loss of key personnel;
•loss of key natural gas producers or the PHMSA, throughproviders of fractionation services;
•reductions in the Officecapacity or allocations of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate theirthird-party pipelines that connect with our subsidiaries pipelines and take measures to protect pipeline segments located in what facilities;
•the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performanceeffectiveness of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments,risk-management policies and procedures and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operationability of our pipelines; however, no estimate can be made at this timesubsidiaries liquids marketing counterparties to satisfy their financial commitments;
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•the likely rangenonpayment or nonperformance by our subsidiaries’ customers;
•regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such expenditures.as our subsidiaries’ construction of additional pipeline systems;
In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were•risks associated with the PHMSA Order. ETP also entered into an Order on Consentconstruction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
•the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;
•a deterioration of the credit and capital markets;
•risks associated with the EPA regarding assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;
•the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
•changes in laws and regulations to which we are subject, including tax, environmental, remediationtransportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and
•the costs and effects of legal and administrative proceedings.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the release site. All requirementsdate on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flowsnew information, future developments or financial position.otherwise.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penaltiesITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(Tabular dollar amounts are in excessmillions)
Market risk includes the risk of $100,000. The case went to hearingloss arising from adverse changes in November 2016market rates and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPVprices. We face market risk from commodity variations, risk and PCO to our West Texas Gulf pipeline in connection with inspectioninterest rate variations, and maintenance activities related to a 2013 incident onlesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.

In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.risks.
12.DERIVATIVE ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peakoff-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage operationssegment and operational gas sales on our interstate transportation and storage operations.segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream operationssegment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
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We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations.sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage operations’segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other operationssegment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage operations,segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table detailstables summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 2022 and 2021 for the Partnership and its consolidated subsidiaries. Dollar amounts are presented in millions.
December 31, 2022December 31, 2021
Notional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% ChangeNotional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures145 $— $— 585 $— $— 
Basis Swaps IFERC/NYMEX(1)
(39,563)54 3 (66,665)(5)1 
Power (Megawatt):
Forwards— 1 — 653,000 2 — 
Futures(21,384)— — (604,920)2 2 
Options – Puts119,200 — — (7,859)— — 
Options – Calls— — — (30,932)— — 
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX42,440 (41)4 6,738 1 1 
Swing Swaps IFERC(202,815)63 7 (106,333)32 31 
Fixed Swaps/Futures(15,758)51 7 (63,898)(24)38 
Forward Physical Contracts2,423 8 1 (5,950)1 — 
NGL (MBbls) – Forwards/Swaps6,934 (41)63 8,493 12 19 
Crude (MBbls) – Forwards/Swaps795 26 22 3,672 13 2 
Refined Products (MBbls) – Futures(3,547)(39)37 (3,349)(15)32 
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX(37,448)22 2 (40,533)1 — 
Fixed Swaps/Futures(37,448)58 17 (40,533)41 14 
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the
127
contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our outstanding commodity-related derivatives:total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
 December 31, 2017 December 31, 2016
 
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives       
(Trading)       
Natural Gas (BBtu):       
Fixed Swaps/Futures1,078
 2018 (683) 2017
Basis Swaps IFERC/NYMEX (1)
48,510
 2018-2020 2,243
 2017
Options – Puts13,000
 2018 —
 —
Power (Megawatt):       
Forwards435,960
 2018-2019 391,880
 2017 - 2018
Futures(25,760) 2018 109,564
 2017 - 2018
Options — Puts(153,600) 2018 (50,400) 2017
Options — Calls137,600
 2018 186,400
 2017
Crude (MBbls) – Futures—
 — (617) 2017
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX4,650
 2018-2020 10,750
 2017 - 2018
Swing Swaps IFERC87,253
 2018-2019 (5,663) 2017
Fixed Swaps/Futures(4,390) 2018-2019 (52,653) 2017 - 2019
Forward Physical Contracts(145,105) 2018-2020 (22,492) 2017
Natural Gas Liquid (MBbls) – Forwards/Swaps6,744
 2018-2019 (5,787) 2017
Refined Products (MBbls) – Futures(3,901) 2018-2019 (3,144) 2017
Corn (Bushels) – Futures1,870,000
 2018 1,580,000
 2017
Fair Value Hedging Derivatives       
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX(39,770) 2018 (36,370) 2017
Fixed Swaps/Futures(39,770) 2018 (36,370) 2017
Hedged Item — Inventory39,770
 2018 36,370
 2017
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Risk
We are exposedAs of December 31, 2022, our subsidiaries had $3.16 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to market risk for changesinterest expense of $32 million annually; however, our actual change in interest rates. To maintainexpense may be less in a cost effective capital structure, we borrow funds using a mix of fixedgiven period due to interest rate floors included in our variable rate debt and variable rate debt.instruments. We also manage a portion of our interest rate exposure by utilizing interest rate swaps, to achieve a desired mix of fixed and variable rate debt. We also utilize forward startingincluding forward-starting interest rate swaps to lock inlock-in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which arewere designated as hedges for accounting purposes:purposes (dollar amounts presented in millions):
Term
Type(1)
Notional Amount Outstanding
December 31, 2022December 31, 2021
July 2022 (2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate$— $400 
July 2023 (2)(3)
Forward-starting to pay a fixed rate of 3.845% and receive a floating rate— 200 
July 2024 (2)
Forward-starting to pay a fixed rate of 3.512% and receive a floating rate400 200 
      Notional Amount Outstanding
Entity Term 
Type(1)
 December 31, 2017 December 31, 2016
ETP 
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
ETP 
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
ETP 
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
ETP 
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
ETP December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
ETP March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1)Floating rates are based on either SOFR or three-month LIBOR.
(1)
(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
(3)This interest rate swap was terminated and settled in 2022.
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of $73 million as of December 31, 2022. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
Floating rates are based on 3-month LIBOR.
(2)
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
TheOur natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers,industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

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Derivative Summary
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following table provides a summaryfinancial statements starting on page F-1 of this report are incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of our derivative assetsmanagement, including Marshall S. McCrea, III and liabilities:
 Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives
 December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives designated as hedging instruments:       
Commodity derivatives (margin deposits)$14
 $—
 $(2) $(4)
 14
 —
 (2) (4)
Derivatives not designated as hedging instruments:       
Commodity derivatives (margin deposits)262
 338
 (281) (416)
Commodity derivatives45
 25
 (58) (58)
Interest rate derivatives—
 —
 (219) (193)
Embedded derivatives in ETP Convertible Preferred Units—
 —
 —
 (1)
 307
 363
 (558) (668)
Total derivatives$321
 $363
 $(560) $(672)
The following table presents the fair valueThomas E. Long, Co-Chief Executive Officers of our recognized derivative assetsGeneral Partner (Co-Principal Executive Officers), and liabilitiesDylan A. Bramhall (Principal Financial Officer), of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including Messrs. McCrea, Long and Bramhall, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2022.
Management’s Report on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:Internal Control over Financial Reporting
    Asset Derivatives Liability Derivatives
  Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives without offsetting agreements Derivative assets (liabilities) $—
 $—
 $(219) $(194)
Derivatives in offsetting agreements:        
OTC contracts Derivative assets (liabilities) 45
 25
 (58) (58)
Broker cleared derivative contracts Other current assets (liabilities) 276
 338
 (283) (420)
  321
 363
 (560) (672)
Offsetting agreements:        
Counterparty netting Derivative assets (liabilities) (21) (4) 21
 4
Counterparty netting Other current assets (liabilities) (263) (338) 263
 338
Total net derivatives $37
 $21
 $(276) $(330)
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

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

13.RETIREMENT BENEFITS:
Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including thosemanagement of ETP, SunocoEnergy Transfer LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. Wesubsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our subsidiaries have made matching contributionsmanagement, including the Co-Chief Executive Officers and Chief Financial Officer of $38 million, $44 million and $40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, respectively.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The fundingour General Partner, we conducted an evaluation of the trust eliminated substantially alleffectiveness of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

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

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

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

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $33
 $33
 $—
 $—
Mutual funds (1)
 154
 154
 —
 —
Fixed income securities 70
 —
 70
 —
Total $257
 $187
 $70
 $—
(1)
Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as of December 31, 2017.
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $23
 $23
 $—
 $—
Mutual funds (1)
 142
 142
 —
 —
Fixed income securities 91
 —
 91
 —
Total $256
 $165
 $91
 $—
(1)
Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.
The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valuedfinancial reporting based on the net asset value per share (or its equivalent)framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  
Contributions
We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
(1)     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
The Medicare Prescription Drug Act provides for a prescription drug benefit under MedicareTreadway Commission (“Medicare Part D”COSO Framework”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

14.RELATED PARTY TRANSACTIONS:
In June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.
ETE previously paid ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.
In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 2015, respectively.
15.REPORTABLE SEGMENTS:
Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
Based on our evaluation under the change inCOSO framework, our reportable segments we have recastmanagement concluded that our internal control over financial reporting was effective as of December 31, 2022.
Grant Thornton LLP, an independent registered public accounting firm, has audited the presentationeffectiveness of our segment results for the prior years to be consistent with the current year presentation.

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

 

 

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

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

 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Investment in ETP$5,901
 $5,810
 $8,167
Investment in Sunoco LP103
 119
 178
Investment in Lake Charles LNG2
 —
 1
Adjustments and Eliminations—
 —
 (123)
Total$6,006
 $5,929
 $8,223
 December 31,
 2017 2016 2015
Advances to and investments in affiliates:     
Investment in ETP$3,816
 $4,280
 $5,003
Adjustments and Eliminations(1,111) (1,240) (1,541)
Total$2,705
 $3,040
 $3,462
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.
Investment in ETP
 Years Ended December 31,
 2017 2016 2015
Intrastate Transportation and Storage$2,891
 $2,155
 $1,912
Interstate Transportation and Storage915
 946
 1,008
Midstream2,510
 2,342
 2,607
NGL and refined products transportation and services8,326
 5,973
 4,569
Crude oil transportation and services11,672
 7,539
 8,980
All Other2,740
 2,872
 15,216
Total revenues29,054
 21,827
 34,292
Less: Intersegment revenues441
 209
 136
Revenues from external customers$28,613
 $21,618
 $34,156
Investment in Sunoco LP
 Years Ended December 31,
 2017 2016 2015
Retail operations$2,263
 $1,991
 $2,226
Wholesale operations9,460
 7,995
 10,204
Total revenues11,723
 9,986
 12,430
Less: Intersegment revenues10
 9
 11
Revenues from external customers$11,713
 $9,977
 $12,419
Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related2022, as stated in their report, which is included herein.
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16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.
 Quarters Ended  
 March 31* June 30* September 30* December 31 Total Year
2017:         
Revenues$9,660
 $9,427
 $9,984
 $11,452
 $40,523
Operating income (loss)758
 746
 924
 285
 2,713
Net income (loss)319
 121
 758
 1,168
 2,366
Limited Partners’ interest in net income232
 204
 240
 239
 915
Basic net income per limited partner unit$0.22
 $0.18
 $0.22
 $0.22
 $0.85
Diluted net income per limited partner unit$0.21
 $0.18
 $0.22
 $0.22
 $0.83
 Quarters Ended  
 March 31* June 30* September 30* December 31* Total Year*
2016:         
Revenues$6,447
 $7,866
 $8,156
 $9,323
 $31,792
Operating income680
 814
 624
 (275) 1,843
Net income (loss)320
 417
 (3) (734) —
Limited Partners’ interest in net income311
 239
 207
 226
 983
Basic net income per limited partner unit$0.30
 $0.23
 $0.20
 $0.22
 $0.94
Diluted net income per limited partner unit$0.30
 $0.23
 $0.19
 $0.21
 $0.92
* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.
The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

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


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


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


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

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


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


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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors of Energy Transfer Partners, L.L.C.LE GP, LLC and
Unitholders of Energy Transfer LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2022, and our report dated February 17, 2023 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP
Dallas, Texas
February 17, 2023
130
Changes in Internal Controls over Financial Reporting
There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2022 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
131
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of Energy Transfer are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement.
As of January 1, 2023, our Board of Directors is comprised of nine persons, four of whom qualify as “independent” under the NYSE’s corporate governance standards. As a limited partnership, we are not required under the NYSE’s corporate governance standards (Section 303A) to have a majority of independent directors. We have determined that Messrs. Anderson, Brannon, Grimm and Perry are all “independent” under the NYSE’s corporate governance standards.
As a limited partnership, we are not required by the rules of the NYSE to seek Unitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of Energy Transfer, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of Energy Transfer.
Board Leadership Structure. We have no policy requiring either that the positions of the Chairman of the Board and the Chief Executive Officer, or CEO, be separate or that they be occupied by the same individual. The Board of Directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances. Previously, the Board of Directors believed that the CEO was best situated to serve as Chairman because he was the director most familiar with the Partnership’s business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. Beginning in 2021, the Board of Directors has established separate roles for the Executive Chairman and Co-Chief Executive Officers. Independent directors and management have different perspectives and roles in strategy development. Our independent directors bring experience, oversight and expertise from outside the Partnership and from a variety of industries, while the Executive Chairman and Co-Chief Executive Officers bring extensive experience and expertise specifically related to the Partnership’s business.
Risk Oversight. Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Co-CEOs, who report to the Board of Directors, have day-to-day risk management responsibilities. Our Co-CEOs attend the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of Energy Transfer’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from Energy Transfer’s internal auditor, who reports directly to the Audit Committee, and reviews Energy Transfer’s contingencies with management and our independent auditors.
Corporate Governance
The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.
Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.
132
Annual Certification
In 2022, our Chief Executive Officer provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards.
Conflicts Committee
Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to Energy Transfer and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to Energy Transfer to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to Energy Transfer. Pursuant to the terms of our Partnership Agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Energy Transfer, approved by all partners of Energy Transfer and not a breach by the general partner or its Board of Directors of any duties they may owe Energy Transfer or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Audit Committee
The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Michael K. Grimm qualified as an audit committee financial expert during 2022. A description of the qualifications of Mr. Grimm may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”
The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and approves the filing of our Form 10-K, which includes our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of Energy Transfer be included in Energy Transfer’s Annual Report on Form 10-K for the year ended December 31, 2022.
The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Grimm serve as elected members of the Audit Committee.
Compensation and Nominating/Corporate Governance Committees
Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Messrs. Anderson and Grimm serve as members of the Compensation Committee.
The responsibilities of the Energy Transfer Compensation Committee include, among other duties, the following:
•annually review and approve goals and objectives relevant to compensation of our Co-CEOs and CFO, if applicable;
•annually evaluate the CEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO and CFO’s compensation levels, if applicable, based on this evaluation;
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•make determinations with respect to the grant of equity-based awards to executive officers under Energy Transfer’s equity incentive plans;
•periodically evaluate the terms and administration of Energy Transfer’s long-term incentive plans to assure that they are structured and administered in a manner consistent with Energy Transfer’s goals and objectives;
•periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
•periodically evaluate the compensation of the directors;
•retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO and CFO or executive officer compensation; and
•perform other duties as deemed appropriate by the Board of Directors.
Code of Business Conduct and Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the co-principal executive officers, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.
Meetings of Non-management Directors and Communications with Directors
Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.
We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer LP, 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.
Directors and Executive Officers of Our General Partner
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of February 17, 2023. Executive officers and directors are elected for indefinite terms.
NameAgePosition with Our General Partner
Kelcy L. Warren67 Executive Chairman of the Board of Directors
Thomas E. Long66 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
Marshall S. (Mackie) McCrea, III63 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
Dylan A. Bramhall46 Group Chief Financial Officer (Principal Financial Officer)
Thomas P. Mason66 Executive Vice President and President - LNG
Bradford D. Whitehurst48 Executive Vice President of Tax and Corporate Initiatives
James M. Wright, Jr.54 Executive Vice President, General Counsel and Chief Compliance Officer
A. Troy Sturrock52 Group Senior Vice President and Controller (Principal Accounting Officer)
Steven R. Anderson73 Director
Richard D. Brannon64 Director
Michael K. Grimm68 Director
John W. McReynolds72 Director
James R. (Rick) Perry72 Director
Matthew S. Ramsey67 Director
Mr. Long, Mr. Mason and Mr. Whitehurst serve as directors of the general partner of USAC.
Set forth below is biographical information regarding the foregoing officers and directors of our general partner:
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Kelcy L. Warren. Mr. Warren serves as Executive Chairman of our general partner. Mr. Warren served as Chief Executive Officer from August 2007 through December 2020. He was appointed Co-Chairman of the Board of Directors of our general partner, effective upon the closing of our IPO, and in August 2007, he became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general partner of ETO until its merger into Energy Transfer LP in April 2021. Prior to August 2007, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETO since the combination of the midstream and intrastate transportation storage operations of La Grange Acquisition, L.P. and the retail propane operations of Heritage in January 2004. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Warren was selected to serve as a director and as Executive Chairman because he previously served as Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States and brings a unique and valuable perspective to the Board of Directors.
Thomas E. Long. Mr. Long has served as the Co-Chief Executive Officer of our general partner since January 2021. Mr. Long served as Chief Financial Officer of Energy Transfer’s general partner from February 2016 until January 2021, and has been a director of our general partner since April 2019. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Chief Financial Officer of ETO until its merger into Energy Transfer LP in April 2021, and was previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. Mr. Long served as a director of Sunoco LP from May 2016 until May 2021, and has served on the Board of USAC since April 2018. In May 2022, Mr. Long was appointed to the board of directors of Texas Capital Bancshares, Inc (NASDAQ: TCBI). Mr. Long was selected to serve on our Board of Directors because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.
Marshall S. (Mackie) McCrea, III. Mr. McCrea has served as the Co-Chief Executive Officer of our general partner since January 2021. Prior to that he was the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of the Energy Transfer family since November 2015. Mr. McCrea has served on the Board of Directors of our general partner since December 2009. Mr. McCrea was appointed as a director of the general partner of ETO in December 2009 and served in that capacity until ETO’s merger into Energy Transfer LP in April 2021. Prior to December 2009, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017. Mr. McCrea was selected to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.
Dylan A. Bramhall. Mr. Bramhall has served as Group Chief Financial Officer of our general partner since November 2022 and currently is also Chief Financial Officer of Sunoco LP’s general partner. Mr. Bramhall joined Energy Transfer in 2015 as a result of its merger with Regency Energy Partners and is responsible for oversight of the Partnership’s Financial Planning and Analysis, Credit and Commodity Risk Management, Insurance, Cash Management, Capital Markets, Accounting, Financial Reporting and Investor Relations groups. He also serves as a member of Energy Transfer’s Risk Oversight Committee. While at Regency, Mr. Bramhall held management positions in the finance, risk, commercial and operations groups. Mr. Bramhall holds a Bachelor of Business Administration in finance and Master of Business Administration in finance and operations management, both from the University of Iowa.
Thomas P. Mason.Mr. Mason has served as Executive Vice President and President - LNG since December 2022. He became Executive Vice President and General Counsel of the general partner of Energy Transfer in December 2015, and served as the Executive Vice President, General Counsel and President - LNG from October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. until December 2022 when he resigned from his role as General Counsel. In February 2021, Mr. Mason assumed leadership responsibility over the Partnership’s newly created Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce Energy Transfer’s environmental footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining Energy Transfer, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason served as a director on the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017 and as a director on the Board of Directors of PennTex Midstream
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Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason has also served as a member of the Board of Directors of USAC since April 2018.
Bradford D. Whitehurst. Mr. Whitehurst has served as Executive Vice President of Tax and Corporate Initiatives of Energy Transfer since November 2022. From January 2021 to November 2022, he served as Chief Financial Officer. From August 2014 through December 2020, he served as Executive Vice President – Head of Tax. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer and its subsidiaries in his role as outside counsel since 2006. He has served as a member of the board of directors of USAC since April 2019.
James M. Wright, Jr. Mr. Wright was appointed as Executive Vice President, General Counsel and Chief Compliance Officer of our general partner in December 2022. He became Executive Vice President - Legal and Chief Compliance Officer of ET’s general partner in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Wright has been a part of the Energy Transfer legal team with increasing levels of responsibility since July 2005 and has held various senior-level positions in the legal department including General Counsel of the general partner of Energy Transfer Partners, L.P. from December 2015 to October 2018 and Deputy General Counsel from May 2008 to December 2015. Prior to joining Energy Transfer, Mr. Wright gained significant experience at Enterprise Products Partners, L.P., El Paso Corp., Sonat Exploration Company and KPMG Peat Marwick LLP. Mr. Wright earned a Bachelor of Business Administration degree in Accounting and Finance from Texas A&M University and a JD from South Texas College of Law.
A. Troy Sturrock. Mr. Sturrock has served as the Group Senior Vice President, Controller and Principal Accounting Officer of our general partner since September 2022. He previously served as Senior Vice President, Controller and Principal Accounting Officer, having assumed that role in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He served as the Senior Vice President, Controller and Principal Accounting Officer of the general partner of ETO from August 2016 until ETO’s merger into Energy Transfer LP in April 2021, and previously served as Vice President, Controller and Principal Accounting Officer of our general partner beginning in June 2015. Mr. Sturrock is a Certified Public Accountant.
Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon’s Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. Mr. Anderson also served as a member of the board of directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. Mr. Anderson was selected to serve on our Board of Directors based on his experience in the midstream energy industry generally, and his knowledge of Energy Transfer’s business specifically. Mr. Anderson also brings recent experience on audit and compensation committees of another publicly traded partnership.
Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the audit committee since April 2016. Mr. Brannon is the CEO of CH4 Energy Six, LLC and Uinta Wax, LLC, both independent companies focused on horizontal oil and gas development. Mr. Brannon previously served on the board of directors of WildHorse Resource Development from its IPO in December 2016 until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Sunoco LP, Regency, OEC Compression and Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business, having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.
Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and served on the audit and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held upstream exploration and production company active in onshore continental United States, and served as its President and Chief Executive Officer from 1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018. From November 2018 until it was sold in 2019, Mr. Grimm served on the Board of Directors of Anadarko Petroleum Corporation. Prior to the formation of Rising Star,
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Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr. Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the American Association of Professional Landmen, Dallas Wildcat Committee, Dallas Producers Club, and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. Mr. Grimm was selected to serve as a director because of his extensive experience in the energy industry and his service as a senior executive at several energy-related companies, in addition to his contacts in the industry gained through his involvement in energy-related organizations.
John W. McReynolds. Mr. McReynolds is a director of Energy Transfer LP, having served in that capacity since August 2004. Mr. McReynolds previously served as the President of Energy Transfer LP from March 2005 until October 2018, at which time he became Special Advisor to the Partnership. Mr. McReynolds also previously served as our Chief Financial Officer from August 2005 to June 2013. Prior to becoming President of Energy Transfer LP, Mr. McReynolds was a partner in the international law firm of Hunton & Williams LLP for over 20 years. As a lawyer, he specialized in energy related finance, securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation, and governmental proceedings, including as an expert in special projects for boards of directors of public companies. Mr. McReynolds was selected to serve in the indicated roles with Energy Transfer because of this extensive background and experience, as well as his many contacts and relationships in the industry.
James R. (Rick) Perry. Mr. Perry was appointed to the Board of Directors of our general partner in January 2020. He formerly served as U.S. Secretary of Energy from March 2017 until December 2019. Prior to that, he served as the Governor of the State of Texas from 2000 until January 2015. Mr. Perry served as Lieutenant Governor of Texas from 1998 to 2000, and as Agriculture Commissioner from 1991 to 1998. Prior to 1991, he also served in the Texas House of Representatives. Mr. Perry previously served on the Board of Directors of ETO from February 2015 until December 2016. Mr. Perry was selected to serve as a director because of his vast experience as an executive in the highest office of state government. In addition, Mr. Perry has been involved in finance and budget planning processes throughout his career in government as a member of the Texas House Appropriations Committee, the Legislative Budget Board and as Governor.
Matthew S. Ramsey. Mr. Ramsey was appointed as a director of Energy Transfer’s general partner in July 2012 and served as a director of ETO’s general partner from November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey served as the Chief Operating Officer or our general partner from October 2018 until his retirement in April 2022, and served as President and Chief Operating Officer of ETO’s general partner from November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey also previously served as a director of Sunoco LP, having served as chairman of Sunoco LP’s board from April 2015 until March 2022, and of USAC, having served on that board from April 2018 until March 2022. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. In addition to his work in the energy business, Mr. Ramsey serves on the board of directors of the National Association of Manufacturers and as a Trustee of the Southwestern Medical Foundation. He is the former Chairman of the University of Texas Chancellor’s Council. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey was selected to serve based on vast experience in the oil and gas space and Energy Transfer believes that he provides valuable industry insight as a member of our Board of Directors.
Delinquent Section 16(a) Reports
Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2022, with the exception of one late Form 4 each for Messrs. Wright, Brannon and McReynolds.
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ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Named Executive Officers
Energy Transfer does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of Energy Transfer’s management functions. As a result, the executive officers of our General Partner are Energy Transfer’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. The persons we refer to in this discussion as our “named executive officers” are the following:
•Marshall S. (Mackie) McCrea, III, Co-Chief Executive Officer;
•Thomas E. Long, Co-Chief Executive Officer;
•Dylan A. Bramhall, Executive Vice President and Group Chief Financial Officer;
•Bradford D. Whitehurst, Executive Vice President — Tax and Corporate Initiatives;
•Thomas P. Mason, Executive Vice President — Alternative Energy and President — LNG; and
•James M. Wright, Jr., Executive Vice President, General Counsel and Chief Compliance Officer.
Our Philosophy for Compensation of Executives
In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for its executive officers, including the named executive officers, that provides for a slightly below the median market annual base compensation (i.e., approximately the 30th to 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short- and long-term performance that are both targeted to pay out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its executive officers, including the named executive officers, to the success of the Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit, phantom unit awards or cash restricted unit awards under the Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of executive officers awards, including awards to the named executive officers, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the Partnership and/or the other affiliated partnerships pay to their respective unitholders.
The Partnership has historically granted restricted unit and/or phantom unit awards (“RSUs”) that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. Beginning in 2020, Energy Transfer began granting cash restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. For 2020, the awards to employees were generally split equally between RSUs and CRSUs; for 2021 and 2022, the awards were generally split based on 75% RSUs and 25% CRSUs. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our General Partner places on aligning the interests of its named executive officers with those of Unitholders. While the Partnership utilizes time-based forms of equity awards, the grant date valuation utilizes a modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are a time-vested vehicle.
As discussed below, our compensation committee and/or the compensation committee of the general partner of Sunoco LP, as applicable, all in consultation with our General Partner, are responsible for the compensation policies and compensation level of our executive officers, including the named executive officers of our General Partner. In this discussion, we refer to our compensation committee as the “Energy Transfer Compensation Committee.”
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For a more detailed description of the compensation to the Partnership’s named executive officers, please see “– Compensation Tables” below.
Distributions to Our General Partner
Our General Partner is majority-owned by Mr. Kelcy Warren. We pay quarterly distributions to our General Partner in accordance with our Partnership Agreement with respect to its ownership of its general partner interest as specified in our Partnership Agreement. The cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per-unit distributions equal the per-unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees.
For a more detailed description of the compensation of our named executive officers, please see “– Compensation Tables” below.
Compensation Philosophy
Our compensation programs are structured to achieve the following:
•reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;
•attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships or other peer companies of similar size and in similar lines of business;
•motivate executive officers and key employees to achieve strong financial and operational performance;
•emphasize performance-based, or “at-risk,” compensation; and
•reward individual performance.
Components of Executive Compensation
For the year ended December 31, 2022, the compensation paid to our named executive officers consisted of the following components:
•annual base salary;
•non-equity incentive plan compensation consisting solely of discretionary cash bonuses;
•time-vested RSUs and CRSUs under the equity incentive plan(s);
•payment of distribution equivalent rights (“DERs”) on unvested time-based RSUs under our equity incentive plan;
•vesting of previously issued time-based RSUs issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and
•401(k) plan employer contributions.
Methodology
The Energy Transfer Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The Energy Transfer Compensation Committee also considers individual performance, levels of responsibility, skills and experience.
Periodically, the Energy Transfer Compensation Committee engages a third-party independent compensation consultant to provide a full market competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, in 2021 Meridian Compensation Partners, LLC (“Meridian”) completed an evaluation of the market competitiveness of total compensation levels of a number of officers of the Partnership, including the named executive officers. The Meridian review provided market information with respect to compensation of Partnership executives, including named executive officers during the year ended December 31, 2021. In particular, the review by Meridian was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive
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officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. The Partnership continued to rely on the Meridian review for calendar year 2022.
In conducting its review, Meridian assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of Energy Transfer. The final “peer group” consisted of the core group of peers (i.e. the eight most similar peers in terms of business, revenues, assets and market value as well as competition for talent at the senior management level) and a group of expanded reference companies composed of a broader group of oil and gas companies, including additional integrated, upstream and midstream comparators whose data provided additional market context. As part of the evaluation conducted by Meridian, a determination was made to focus the analysis largely on the core energy industry peers. This decision was based on a determination that the core peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This focus allowed Meridian to report on this specific core peer data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies, while at the same time considering whether the context provided by the expanded group offered additional information that should be considered by the Compensation Committee. The core identified companies were:
Energy Peer Group:
• Conoco Phillips• Marathon Petroleum Corporation
• Enterprise Products Partners, L.P.• Kinder Morgan, Inc.
• Plains All American Pipeline, L.P.• The Williams Companies, Inc.
• Valero Energy Corporation• Phillips 66
The compensation analysis provided by Meridian covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives. In preparing the review materials, Meridian utilized generally accepted compensation principles and gathered data from public disclosures of peer companies, including Form 10-K and proxy data and published survey data from multiple sources that are relevant to Energy Transfer’s core peer group, industry, financial size and operational breadth. The Meridian review process also included significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow Meridian the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.
Following Meridian’s 2021 review, the Energy Transfer Compensation Committee reviewed the information provided, including Meridian’s specific conclusions and recommended considerations for all compensation going forward. The Energy Transfer Compensation Committee considered and reviewed the results of the study performed by Meridian to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Meridian’s conclusions and recommendations. While Meridian found that the Partnership is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments could be considered moving forward to allow the Partnership to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). Certain of Meridian’s suggested adjustments as part of the review were implemented and others were determined to require additional review and consideration.
In addition to the information received as part of Meridian’s review, the Energy Transfer Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third-party surveys, although third-party survey data is not used by the Energy Transfer Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers.
Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e., approximately the 30th to 40th percentile of market) and are determined by the Energy Transfer Compensation Committee after taking into account the recommendations of Mr. Warren.
During the merit review process, the Energy Transfer Compensation Committee considers the recommendations of Mr. Warren, any relevant compensation study data (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. During 2022, the Energy Transfer Compensation Committee approved a 4%
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increase to the base salary of Mr. McCrea to $1,399,320 from the prior level of $1,345,500; a 4% increase to the base salary of Mr. Long to $1,399,320 from the previous level of $1,345,500; an approximately 4% increase to the base salary of Mr. Whitehurst to $640,425 from the previous level of $615,825; and an approximately 4% increase to the base salary of Mr. Mason to $679,695 from the previous level of $653,495.
In connection with his promotion to Group Chief Financial Officer effective November 11, 2022, the Energy Transfer Compensation Committee had previously approved an increase in the annual base salary of Mr. Bramhall to $575,000 from its previous level of $425,000. In connection with his promotion to General Counsel effective November 30, 2022, the Energy Transfer Compensation Committee approved an increase in the annual base salary of Mr. Wright to $550,000 from its previous level of $475,000.
Annual Bonus. In addition to base salary, the Energy Transfer Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Bonus Plan.
The Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Bonus Plan is administered by the Energy Transfer Compensation Committee and the Energy Transfer Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan.
For each calendar year or any other period designated by the Energy Transfer Compensation Committee (the “Performance Period”), the Energy Transfer Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). For purposes of the Adjusted EBITDA Target and the DCF Target established in the Bonus Plan, the measures of Adjusted EBITDA and Distributable Cash Flow are calculated using the same definitions as used in the Partnership’s publicly reported financial information, including the Partnership’s earnings press releases, investor presentations, and annual and quarterly filings on Forms 10-K and 10-Q. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.
While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the Performance Period in light of the contribution of each individual to our profitability and success during such year. The Energy Transfer Compensation Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The Energy Transfer Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.
For Messrs. McCrea and Long, their 2022 bonus pool targets were 160% of their respective annual base earnings, consistent with their previous 2021 targets. For 2022, the Energy Transfer Compensation Committee approved short-term annual cash bonus pool targets for Messrs. Whitehurst, Bramhall and Mason of 130% of their respective annual base earnings, consistent with their previous 2021 targets. In connection with his promotion to General Counsel Mr. Wright’s bonus target for 2022 was increased 130% from its prior level of 115%.
In February 2023, the Energy Transfer Compensation Committee certified 2022 performance results under the Bonus Plan and authorized payment of 120% of the targeted pool. This bonus payout reflected the achievement of 110% of the Adjusted EBITDA Target, 116% of the DCF Target and 94% of, or $47 million under, the Department Budget Target. The Energy Transfer Compensation Committee also used its discretion under the Bonus Plan to exceed the 110% of the achieved pool target
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result and approved a total payout of 120% of the targeted pool amount. The funding of the 120% target was authorized as a result of the significant achievements above the targeted performance metrics.
Based on the approved results, the Energy Transfer Compensation Committee approved a cash bonus relating to the 2022 calendar year to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright in the amounts of $2,635,027, $2,635,027, $700,000, $950,000, $1,040,900 and $762,540, respectively.
Equity Awards. Energy Transfer maintains and operates (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”); the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”); (iv) the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (the “Energy Transfer Plan,” together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “Energy Transfer Incentive Plans”). The Energy Transfer Incentive Plans authorize the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, under each respective plan of RSUs upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the Energy Transfer Incentive Plans. Energy Transfer has generally used time-vested restricted units and/or phantom units as the vehicle for its annual equity awards to eligible employees, including the named executive officers.
In addition, in 2020, Energy Transfer adopted the Energy Transfer LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the Energy Transfer Incentive Plans, awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis, and the CRU Plan is included for purposes of these discussions as an “Energy Transfer Incentive Plan.”
For 2022, the Energy Transfer Compensation Committee established long-term incentive targets for Messrs. McCrea and Long of 900% of their annual base earnings, consistent with their previous targets. In connection with his promotion to Group Chief Financial Officer effective November 11, 2022, the Energy Transfer Compensation Committee established the long-term incentive target for Mr. Bramhall of 500% of his annual base earnings, which was an increase from his previous target of 300% of annual base earnings. For 2022, the Energy Transfer Compensation Committee approved long-term incentive targets for Messrs. Whitehurst, Mason and Wright of 500%, 500% and 300%, respectively, of their respective annual base earnings, consistent with their previous targets.
The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the named executive officers. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by considering Energy Transfer’s modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are time-vested vehicles. For purposes of establishing an initial price, Energy Transfer utilizes a 60 trading-day trailing weighted average price of Energy Transfer common units prior to November 1, 2022. This average trading price is then subject to adjustment when Energy Transfer’s TUR is more than 5% greater or less than that of its identified peer group. If the TUR analysis yields a result that is within 5% percent of its identified peer group, the Energy Transfer Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target pool for each eligible participant, including the named executive officers. If Energy Transfer’s TUR is outside of the 5% deviation, the 60 trading day trailing weighted average will be adjusted up or down to a maximum of 15% from the trailing weighted average price based on Energy Transfer’s performance as compared to the identified group. For 2022, the peer group included the following:
• Enterprise Products Partners, L.P.• Plains All American Pipeline, L.P.
• The Williams Companies, Inc.• MPLX LP
• Kinder Morgan, Inc.
For 2022, the Partnership’s TUR outperformed the identified peer group by approximately 35% based on the average of the identified comparison periods. Consequently, the 2022 long-term incentive base price was decreased to increase the total available restricted pool by the maximum of 15%.
In December 2022, the Energy Transfer Compensation Committee in consultation with Mr. Warren approved grants of RSUs to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 958,950 units, 958,950 units, 175,125 units, 243,750 units, 258,788 units, and 131,250 units, respectively. The Energy Transfer Compensation Committee also approved grants of CRSUs
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to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 319,650 units, 319,650 units, 58,375 units, 81,250 units, 86,262 units and 43,750 units, respectively.
The RSUs granted in 2022 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year. Vesting of the awards is generally subject to continued employment through each specified vesting date. The RSU awards entitle the recipients to receive, with respect to each Energy Transfer unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by Energy Transfer to its common unitholders.
The CRSUs granted in 2022 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the award recipient to receive cash equal to the market value of one Energy Transfer common unit upon vesting. The CRSU do not include rights to DER cash payments.
In approving the grant of such RSUs and CRSUs, including to the named executive officers, the Energy Transfer Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of Energy Transfer’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2022 awards would accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of Energy Transfer as that term is defined under the Energy Transfer Incentive Plans.
For 2020, Mr. McCrea did not receive an award of CRSUs; instead, he received a special one-time time vested cash award of $5,000,000 payable as follows:
•$1,800,000 on December 31, 2020;
•$1,600,000 on July 1, 2021; and
•$1,600,000 on December 5, 2022.
This amount is intended to approximate 50% of Mr. McCrea’s targeted annual equity award and replace the award of CRSUs made to other named executive officers. The last payment of $1,600,000 was made during 2022.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity awards would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the award agreements for the RSUs and CRSUs awarded in 2020, as well as other awards outstanding held by Partnership employees, including the named executive officers, also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards under the Energy Transfer Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section 409(A), which may include a six (6) month delay in the vesting after retirement.
We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.
Affiliate and Subsidiary Equity Awards. In addition to his role as an officer for Energy Transfer during 2022, Mr. Bramhall has certain responsibilities for Sunoco LP, including a leadership role for certain shared service functions.
The Sunoco LP Compensation Committee in December 2022 approved a grant of RSUs to Mr. Bramhall of 14,200 restricted units, under the 2018 Sunoco LP Plan. The terms and conditions of the restricted unit to Mr. Bramhall under the 2018 Sunoco LP Plan provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the award would be accelerated in the event of his death or disability, or upon a change in control. The retirement acceleration provisions for this award under the 2018 Sunoco LP Plan are the same as the retirement acceleration provisions under Energy Transfer Incentive Plans with the ability to accelerate at retirement 40% of outstanding unvested awards at age 65 and 50% at age 68.
Special One-Time Awards to Co-Chief Executive Officers. In recognition of their assumption of their new roles as Co-Chief Executive Officers effective January 1, 2021, the Energy Transfer Compensation Committee approved certain one-time awards to Messrs. McCrea and Long.
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Mr. McCrea received a special one-time award of 241,815 RSUs under the Energy Transfer Incentive Plans and a special cash payment of $1,625,000 in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
Mr. Long received a special one-time award of 483,630 RSUs under the Energy Transfer Incentive Plans in connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
The RSU awards to Messrs. McCrea and Long were made at the same grant date valuation and vesting schedules used for the annual equity awards described above under “—Equity Awards” section above. These awards were approved by the Energy Transfer Compensation Committee on December 30, 2020 to be effective immediately upon Messrs. McCrea and Long assuming their new roles on January 1, 2021 and are reflected as compensation in 2021 in the Compensation Tables section below.
Unit Ownership Guidelines. In 2021, the Board of Directors of our General Partner adopted an update to the Executive Unit Ownership Guidelines (the “Guidelines”), which sets forth minimum ownership guidelines applicable to certain executives of Energy Transfer with respect to Energy Transfer and Sunoco LP common units, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, (i) the Chief Executive Officer/Co-Chief Executive Officer(s) are expected to own common units having a minimum value of six times base salary; (ii) the Chief Operating Officer, the Chief Financial Officer, the General Counsel and other C-Suite executives expected to own common units having a minimum value of four times their respective base salary; and (iii) Senior Vice Presidents are expected to own common units having a minimum value of two times their respective base salary. In addition to the named executive officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from one to four times their respective base salary.
The Energy Transfer Compensation Committee believes that the ownership of Energy Transfer and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to Energy Transfer’s total unitholder return, aligning the interests of such executives with those of Unitholders, and promoting Energy Transfer’s interest in good corporate governance.
Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines. As of December 31, 2022, all of the named executive officers were compliant with the level required of the Guidelines as of that date.
Covered executives may satisfy the Guidelines through direct ownership of Energy Transfer and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of Energy Transfer and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.
Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.
Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “Energy Transfer 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. During 2020, in response to challenging conditions within the industry, including impacts of the COVID-19 pandemic, Energy Transfer suspended its 401(k) matching contribution from July 1, 2020 through December 31, 2020. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.
The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service. As with the 401(k) matching contributions, Energy Transfer suspended the profit
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sharing contribution from July 1, 2020 through December 31, 2020; however, the profit sharing contributions were reinstated for the full year 2021 and continued throughout 2022.
Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in the Partnership’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.
Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to the named executive officers under the Energy Transfer Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”) provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional information.
In addition, in 2021 the Partnership has also adopted the Partnership Severance Plan and Summary Plan Description effective as of December 1, 2021, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.
Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “Energy Transfer NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the Energy Transfer NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the Energy Transfer NQDC Plan, Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the Energy Transfer NQDC Plan) of Energy Transfer, all Energy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the Energy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement.
Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of Unitholders and our subsidiaries’ unitholders for our long-term performance.
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Tax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation
We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes.
Accounting for Non-Cash Compensation
For non-cash compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 2 and Note 9 to our consolidated financial statements.
Compensation Committee Interlocks and Insider Participation
Mr. Steven R. Anderson and Mr. Michael K. Grimm are the only members of the Energy Transfer Compensation Committee. Mr. Ray W. Washburne also served as a member of the Compensation Committee prior to his resignation from the board of directors of our General Partner effective April 1, 2022. During 2022, no member of the Energy Transfer Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. Neither Mr. Grimm nor Mr. Washburne is a former employee of ours or any of our subsidiaries. Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009, as discussed in his biographical information included in “Item 10. Directors, Executive Officers and Corporate Governance.”
Report of Compensation Committee
The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of Energy Transfer. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

The Compensation Committee of the
Board of Directors of LE GP, LLC,
general partner of Energy Transfer LP

Steven R. Anderson
Michael K. Grimm
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.
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Compensation Tables
Summary Compensation Table
Name and Principal PositionYearSalary
($)		Bonus
($)
Equity
Awards (1)
($)
Non-Equity
Incentive Plan
Compensation(2)
($)
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
All Other
Compensation (3)
($)
Total
($)
Thomas E. Long2022$1,372,410 $— $14,344,161 $2,635,027 $— $23,917 $18,375,515 
Co-Chief Executive Officer20211,322,750 — 15,224,039 3,156,400 — 27,014 19,730,203 
2020623,077 — 2,781,255 — — 21,603 3,425,935 
Marshall S. (Mackie) McCrea, III (4)
20221,372,410 1,600,000 14,344,161 2,635,027 — 22,794 19,974,392 
Co-Chief Executive Officer20211,322,750 3,225,000 13,734,458 3,156,400 — 22,044 21,460,652 
20201,157,423 1,800,000 4,597,516 — — 18,045 7,572,984 
Dylan A. Bramhall2022429,808 — 3,241,514 700,000 — 16,298 4,387,620 
Group Chief Financial Officer
Bradford D. Whitehurst2022628,125 — 3,646,060 950,000 — 18,510 5,242,695 
Executive Vice President – Tax and Corporate Initiatives2021605,413 — 3,102,694 1,174,000 — 15,760 4,897,867 
2020581,202 — 2,596,850 — — 16,224 3,194,276 
Thomas P. Mason2022666,595 — 3,870,995 1,040,900 21,917 5,600,407 
Executive Vice President – Alternative Energy and President – LNG2021642,445 — 3,279,498 1,252,000 — 22,706 5,196,649 
2020655,680 — 2,609,350 — — 20,007 3,285,037 
James M. Wright, Jr.2022488,808 — 1,963,263 762,540 18,550 19,120 3,252,281 
Executive Vice President, General Counsel and Chief Compliance Officer
(1)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. For Messrs. Long, Bramhall and Whitehurst amounts for one or more periods include equity awards of our subsidiary, Sunoco LP, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. Although the CRSU awards may only be settled in cash, they are based upon the value of Energy Transfer common units and are accounted for as equity awards within these compensation tables.
(2)Energy Transfer maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis.
(3)The amounts reflected for 2022 in this column include (i) matching contributions to the Energy Transfer 401(k) Plan made on behalf of the named executive officers of $15,250 each for Messrs. Long, McCrea, Bramhall, Whitehurst, Mason and Wright, and (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long, McCrea, Whitehurst and Wright, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2022, distribution payments in connection with distribution equivalent rights totaled $2,072,643 for Mr. Long, $2,826,685 for Mr. McCrea, $340,120 for Mr. Bramhall, $798,532 for Mr. Whitehurst, $791,164 for Mr. Mason, and $334,890 for Mr. Wright; these amounts include distribution payments on Sunoco LP unit awards for those executives with such unvested awards.
(4)The amounts reflected in the bonus column for Mr. McCrea includes the second payment of Mr. McCrea’s time-vested cash award, which award represented 50% of Mr. McCrea’s total equity award target in 2020. These bonus amounts were paid as follows: $1,800,000 on December 31, 2020, $1,600,000 on July 1, 2021 and $1,600,000 on December 5, 2022. For 2021, the bonus amount reflected above also includes the vesting and payment on February 1, 2021 of a one-time, time-vested cash award of $1,625,000 to Mr. McCrea, which was originally granted in October 2020 in connection with Mr. McCrea’s assumption of his role as Co-Chief Executive Officer.
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Grants of Plan-Based Awards in 2022
NameGrant DateAll Other Unit Awards: Number of Units
(#)
Grant Date Fair Value of Unit Awards (1)
Energy Transfer Unit Awards:
Thomas E. Long12/12/2022958,950 $11,219,715 
Marshal S. (Mackie) McCrea, III12/12/2022958,950 11,219,715 
Dylan A. Bramhall12/12/2022175,125 2,048,963 
Bradford D. Whitehurst12/12/2022243,750 2,851,875 
Thomas P. Mason12/12/2022258,788 3,027,820 
James M. Wright, Jr.12/12/2022131,250 1,535,625 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long12/12/2022319,650 3,124,446 
Marshal S. (Mackie) McCrea, III12/12/2022319,650 3,124,446 
Dylan A. Bramhall12/12/202258,375 570,591 
Bradford D. Whitehurst12/12/202281,250 794,185 
Thomas P. Mason12/12/202286,262 843,175 
James M. Wright, Jr.12/12/202243,750 427,638 
Sunoco LP Unit Awards:
Dylan A. Bramhall12/12/202214,200 621,960 
(1)We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
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Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.
Outstanding Equity Awards at 2022 Fiscal Year-End
Name
Grant Date(1)
Unit Awards (1)
Number of Units That Have Not Vested(2)
(#)
Market or Payout Value of Units That Have Not Vested (3)
($)
Energy Transfer Unit Awards:
Thomas E. Long12/12/2022958,950 $11,382,737 
12/16/20211,121,250 13,309,238 
12/30/2020662,180 7,860,077 
12/16/201986,000 1,020,820 
12/18/201854,590 647,983 
10/19/201846,080 546,970 
Marshal S. (Mackie) McCrea, III12/12/2022958,950 11,382,737 
12/16/20211,121,250 13,309,238 
12/30/2020988,165 11,729,519 
12/16/2019272,960 3,240,035 
12/18/2018242,296 2,876,054 
Dylan A. Bramhall12/12/2022175,125 2,078,734 
12/16/202183,400 989,958 
12/30/202037,500 445,125 
12/16/201921,000 249,270 
12/18/201818,000 213,660 
Bradford D. Whitehurst12/12/2022243,750 2,893,313 
12/16/2021228,000 2,706,360 
12/30/2020166,600 1,977,542 
12/16/201960,920 723,120 
12/18/201854,076 641,882 
Thomas P. Mason12/12/2022258,788 3,071,814 
12/16/2021300,300 3,564,561 
12/30/2020234,900 2,788,263 
12/16/201985,920 1,019,870 
12/18/201876,256 905,159 
James M. Wright, Jr.12/12/2022131,250 1,557,938 
12/16/2021131,944 1,566,175 
12/30/202098,755 1,172,222 
12/16/201936,120 428,744 
12/18/201832,060 380,552 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long12/12/2022319,650 3,179,882 
12/16/2021249,167 2,589,238 
12/30/202059,517 646,228 
Marshal S. (Mackie) McCrea, III12/12/2022319,650 3,179,882 
12/16/2021249,167 2,589,241 
Dylan A. Bramhall12/12/202258,375 580,715 
12/16/202118,534 192,598 
12/30/202012,500 135,723 
Bradford D. Whitehurst12/12/202281,250 808,276 
12/16/202150,667 526,511 
12/30/202055,534 602,981 
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Thomas P. Mason12/12/202286,262 858,135 
12/16/202166,734 693,472 
12/30/202078,300 850,172 
James M. Wright, Jr.12/12/202243,750 435,226 
12/16/202129,321 304,692 
12/30/202032,919 357,427 
Sunoco LP Unit Awards:
Thomas E. Long12/30/202027,800 1,198,180 
12/16/20197,800 336,180 
12/19/20187,730 333,163 
Dylan A. Bramhall12/12/202214,200 612,020 
12/16/202113,000 560,300 
12/30/202016,000 689,600 
10/27/202020,000 862,000 
Bradford D. Whitehurst12/16/202116,100 693,910 
12/30/202026,000 1,120,600 
12/16/20197,280 313,768 
12/19/20187,658 330,060 
James M. Wright, Jr.12/19/201832,060 1,381,786 
(1)Certain of these outstanding awards represent subsidiary awards that converted into Energy Transfer awards upon the in connection with restructuring transactions in prior periods.
(2)Energy Transfer and Sunoco LP unit awards outstanding vest as follows:
•at a rate of 60% in December 2025 and 40% in December 2027 for awards granted in December 2022;
•at a rate of 60% in December 2024 and 40% in December 2026 for awards granted in December 2021;
•at a rate of 60% in December 2023 and 40% in December 2025 for awards granted in December 2020;
•100% in December 2024 for the remaining outstanding portion of awards granted in December 2019; and
•100% in December 2023 for the remaining outstanding portion of awards granted in October and December 2018.
Such awards may be settledat the election of the Energy Transfer Compensation Committee in (i) common units of Energy Transfer (subject to the approval of the Energy Transfer Incentive Plans prior to the first vesting date by a majority of Unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the Energy Transfer Incentive Plans) of the Energy Transfer common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of Energy Transfer common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the Energy Transfer Compensation Committee in its discretion.
Energy Transfer cash restricted unit awards granted in December 2022 vest 1/3 per year in December 2023, 2024 and 2025. Energy Transfer cash restricted unit awards granted in December 2021 vest 1/2 per year in December 2023 and 2024. The remaining outstanding Energy Transfer cash restricted unit awards granted in December 2020 vest in December 2023.
(3)Market value was computed as the number of unvested awards as of December 31, 2022 multiplied by the closing price of respective common units of Energy Transfer and Sunoco LP. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution equivalent rights.
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Units Vested in 2022
Unit Awards
NameNumber of Units
Acquired on Vesting
(#)
Value Realized on Vesting
($) (1)
Energy Transfer Unit Awards:
Thomas E. Long177,430 $2,161,097 
Marshall S. (Mackie) McCrea, III624,392 7,605,095 
Dylan A. Bramhall31,500 383,670 
Bradford D. Whitehurst129,758 1,580,452 
Thomas P. Mason183,000 2,228,940 
James M. Wright, Jr.54,180 659,912 
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long184,100 2,242,342 
Marshall S. (Mackie) McCrea, III124,583 1,517,421 
Dylan A. Bramhall21,766 265,110 
Bradford D. Whitehurst80,866 984,948 
Thomas P. Mason111,666 1,360,092 
James M. Wright, Jr.47,578 579,500 
Sunoco LP Unit Awards:
Thomas E. Long18,539 812,008 
Bradford D. Whitehurst16,340 715,692 
Thomas P. Mason7,643 334,763 
(1)Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date.
We have not issued option awards.
Nonqualified Deferred Compensation Table
A description of the key provisions of the Partnership’s deferred compensation plan can be found in the compensation discussion and analysis above.
NameExecutive Contributions in Last FY ($)
Acquired on Vesting
(#)
Registrant Contributions in Last FY ($)
($) (1)
Aggregate Earnings in Last FY ($) (1)
Aggregate Withdrawals/Distributions ($)Aggregate Balance at Last FYE ($)
James M. Wright, Jr.— — 18,550 — 69,745 
(1)Amounts included in the aggregate earnings column above have been included in the change in non-qualified deferred compensation earnings column of the summary compensation table.
Potential Payments Upon a Termination or Change of Control
Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards (including cash restricted unit awards) granted pursuant the Energy Transfer Incentive Plans will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of Energy Transfer or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of Energy Transfer; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of Energy Transfer in one or more transactions to anyone other than an affiliate of Energy Transfer.
In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards, phantom unit awards and cash restricted unit awards under the Energy Transfer Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding to the named executive officers under the Energy Transfer
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Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the Partnership.
The October 2018 equity award to Mr. Long included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates.
In addition, the Energy Transfer Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least five years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A). Beginning with awards granted in 2022, the retirement provision also requires that the award be held for at least one year after the grant date in order to be eligible for acceleration.
Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the Energy Transfer NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the Energy Transfer NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).
CEO Pay Ratio
In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Messrs. Long and McCrea, Co-Chief Executive Officers, and the annual total compensation of our employees.
For the 2022 calendar year, the annual total compensation of Messrs. Long and McCrea, as reported in the Summary Compensation Table of this Item 11 was $18,375,515 and $19,974,392, respectively.
The median total compensation of the employees supporting the Partnership (other than Messrs. Long and McCrea) was $132,358 for 2022, which amount was updated from the 2021 “median employee.”
Based on this information, for 2022 the ratio of the annual total compensation of Messrs. Long and McCrea to the median of the annual total compensation of the employees supporting the Partnership as of December 31, 2022 was approximately 139 to 1 and 151 to 1, respectively.
To identify the median of the annual total compensation of the employees supporting the Partnership, the following steps were taken:
1.It was determined that, as of December 31, 2022, the applicable employee populations consisted of 9,533 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2022 that are required to be included in our employee population for the CEO pay ratio evaluation.
2.To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2021, and for 2022, updated the compensation of the “median employee” as reflected in our payroll records as reported on form W-2 for 2022.
3.We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”
4.Once we identified our median employee, we combined all elements of the employee’s compensation for 2022 resulting in an annual compensation of $132,358 with total base salary of $113,189 The difference between such employee’s total
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earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $12,827) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $6,342 per employee, includes $4,097 per employee on average matching contribution and $2,245 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).
5.With respect to Messrs. Long and McCrea, we used the amount reported in the “Total” column of our 2022 Summary Compensation Table under this Item 11.
Director Compensation
In 2022, the compensation arrangements for outside directors included a $100,000 annual retainer for services on the board. If a director served on the Energy Transfer Audit Committee, such director would receive an annual cash retainer ($15,000 or $25,000 in the case of the chairman). If a director served on the Energy Transfer Compensation Committee, such director would receive an annual cash retainer ($7,500 or $15,000 in the case of the chairman). The fees for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment.
The outside directors of our General Partner are also entitled to an annual restricted unit award under the Energy Transfer Incentive Plans equal to an aggregate of $100,000 divided by the closing price of Energy Transfer common units on the date of grant. These Energy Transfer common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the Energy Transfer common units and is recognized over the vesting period. Distributions are paid during the vesting period.
The compensation paid to the non-employee directors of our General Partner in 2022 is reflected in the following table:
Name
Fees Paid in Cash(1)
($)
Unit Awards(2)
($)
All Other Compensation
($)		Total
($)
Steven R. Anderson$122,500 $100,000 $— $222,500 
Richard D. Brannon125,000 100,000 — 225,000 
Ray C. Davis (3)
100,000 100,000 — 200,000 
Michael K. Grimm130,000 100,000 — 230,000 
James R. Perry100,000 100,000 — 200,000 
Ray W. Washburne (4)
53,750 100,000 — 153,750 
(1)Fees paid in cash are based on amounts paid during the period.
(2)Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718, disregarding any estimates for forfeitures. See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.
(3)Mr. Davis resigned from the board of directors of our General Partner, effective December 31, 2022.
(4)Mr. Washburne resigned from the board of directors of our General Partner, effective April 1, 2022.
As of December 31, 2022, Mr. Anderson had 39,390 unvested Energy Transfer restricted units outstanding, Mr. Brannon had 40,645 unvested Energy Transfer restricted units outstanding, Mr. Davis had 39,390 unvested Energy Transfer restricted units outstanding, Mr. Grimm had 47,415 unvested Energy Transfer restricted units outstanding and Mr. Perry had 43,868 unvested Energy Transfer restricted units outstanding.
Non-independent directors do not receive compensation for their service on the board of our General Partner. Non-independent directors include the executive chairman and the employee directors, as well as Messrs. McReynolds and Ramsey, both of whom recently retired from the Partnership. In connection with his retirement, as previously reported by the Partnership, Mr. Ramsey received accelerated vesting of certain equity awards granted during his employment. The vesting of those equity awards was determined in connection with Mr. Ramsey’s employment and retirement, not his service on the board; therefore, no compensation is reflected in the table above for such vesting.
For 2023, the Board has adopted new compensation arrangement for outside directors, which will raise the annual restricted unit award under the Energy Transfer Incentive Plans equal to an aggregate of $125,000. The awards using the same grant date valuation as is used for annual long-term incentive awards made to Partnership officers, including the named executive officers, through the annual modified total unitholder return analysis. Additionally, moving forward awards to outside directors will be made at the same time such awards are made to the Partnership officers, usually in December of each year.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Equity Compensation Plan Information
The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2022:
Plan CategoryNumber of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)		Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)		Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
Equity compensation plans approved by security holders— $— — 
Equity compensation plans not approved by security holders37,713,968 — 3,578,984 
Total37,713,968 $— 3,578,984 
Energy Transfer LP Units
The following table sets forth certain information as of February 10, 2023, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.
Beneficially Owned (2)
Percent of Class
Name and Address of
Beneficial Owner (1)
Common Units
Class A
Units(3)
Common UnitsClass A Units
Kelcy L. Warren (4)
287,799,984 765,993,4299.3 %100.0 %
Thomas E. Long773,628 — *N/A
Marshall S. (Mackie) McCrea, III3,085,646 — *N/A
Dylan A. Bramhall109,943 — *N/A
Thomas P. Mason744,056 — *N/A
Bradford D. Whitehurst (5)
538,709 — *N/A
James M. Wright, Jr.221,266 — *N/A
Steven R. Anderson (6)
1,555,163 — *N/A
Richard D. Brannon (7)
696,071 — *N/A
Michael K. Grimm (8)
688,941 — *N/A
John W. McReynolds (9)
30,225,200 — *N/A
James R. Perry126,027 — *N/A
Matthew S. Ramsey1,121,845 — *N/A
Blackstone Holdings I/II GP L.L.C. (10)
160,737,127 — 5.2 %N/A
All Directors and Executive Officers as a group (14 persons)327,802,291 765,993,429 10.6 %100.0 %
*    Less than 1%
(1)The address for all listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.
(2)Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power
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unless otherwise noted. The beneficial ownership of each listed person is based on 3,094,593,760 common units outstanding in the aggregate as of February 10, 2023.
(3)The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units and are not entitled to distributions and otherwise have no economic attributes. The Energy Transfer Class A Units are not convertible into, or exchangeable for, Partnership common units. Under the terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to the general partner additional Energy Transfer Class A Units such that Mr. Warren, through his majority ownership of our general partner, maintains the approximately 20% voting percentage in the Partnership represented by such Energy Transfer Class A Units equivalent to such Energy Transfer Class A Unit voting interest prior to such issuance of additional common units. This provision of the Energy Transfer Class A Units shall terminate at such time as Mr. Warren ceases to be an officer or director of our general partner, provided that all Energy Transfer Class A Units outstanding at such time shall be unchanged and remain outstanding. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(4)Includes 120,385,650 common units held by Kelcy Warren Partners, L.P. and 10,224,429 common units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 100,577,803 common units held by Kelcy Warren Partners III, LLC formerly known as Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 common units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also includes 601,076 common units and 765,933,429 Energy Transfer Class A Units held by LE GP, LLC. Mr. Warren may be deemed to own common units and Energy Transfer Class A Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. Mr. Warren disclaims beneficial ownership of common units and Energy Transfer Class A Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 104,166 common units held by Mr. Warren’s spouse. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
(5)Includes 297,617 common units held by Mr. Whitehurst in a margin account.
(6)Includes 1,544,558 common units held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee.
(7)Includes 580,000 common units held by B4 Capital Investments, LP, a limited partnership of which a limited liability company owned by Mr. Brannon and his wife is the sole general partner and of which Mr. Brannon and his wife are the sole limited partners.
(8)Includes 530,173 common units held Grimm Family Limited Partnership, a limited partnership of which a limited liability company owned by Mr. Grimm is the sole general partner.
(9)Includes 17,445,608 common units held by McReynolds Energy Partners L.P. and 12,142,593 common units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of common units owned by such limited partnerships other than to the extent of his interest in such entities.
(10)This information is based on a Schedule 13G filed on February 9, 2023 by Blackstone Holdings I/II GP L.L.C. on behalf of itself and Blackstone Inc., Blackstone Group Management L.L.C., and Stephen A. Schwarzman, each of which reported sole voting and dispositive power with respect to 160,737,127 Energy Transfer Common Units. The sole member of Blackstone Holdings I/II GP L.L.C. is Blackstone Inc. The sole holder of the Series II preferred stock of Blackstone Inc. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. The address for each reporting person identified in the February 9, 2023 filing was 345 Park Avenue, New York, NY 10154.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Partnership’s principal sources of cash flow are derived from cash flows from the operations of its subsidiaries, including its direct and indirect investments in the limited partner and general partner interests in Sunoco LP and USAC, both of which are limited partnerships engaged in energy-related services.
In making its director independence determination, the Board considered business arrangements involving a director who owns equity interest in, and is the CEO of, a company that owns working interests in oil and gas wells, and affiliates of the Partnership who made nominal payments to that company. None of the arrangements involved payments to the company of more than $1 million in any of the past three fiscal years and the Board determined that the relationship did not impact the director’s independence.
For a discussion of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”
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As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The Partnership Agreement of Energy Transfer provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to Energy Transfer, approved by all the partners of Energy Transfer and not a breach by the General Partner or its Board of Directors of any duties they may owe Energy Transfer or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Additional information on our related party transactions is included in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in millions):
 Years Ended December 31,
 20222021
Audit fees (1)
$10.8 $10.7 
Audit-related fees(2)
— 0.3 
Total$10.8 $11.0 
(1)Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal control over financial reporting.
(2)Includes fees for financial due diligence related to acquisitions.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2022 and 2021 were pre-approved by the Audit Committee in accordance with this policy.
The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
•the auditors’ internal quality-control procedures;
•any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
•the independence of the external auditors;
•the aggregate fees billed by our external auditors for each of the previous two years; and
•the rotation of the lead partner.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as a part of this Report:
Page
(1) Financial Statements – see Index to Financial Statements
F - 1
(2) Financial Statement Schedules – None
(3) Exhibits – see Index to Exhibits
159
157
ITEM 16. FORM 10-K SUMMARY
None.
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Table of Contents
INDEX TO EXHIBITS
The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.
Exhibit
Number
Description
2.1
Agreement and Plan of Merger, dated as of September 15, 2019, by and among Energy Transfer LP, Nautilus Merger Sub LLC and SemGroup Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed September 16, 2019)
2.2
Agreement and Plan of Merger, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC, solely for the purpose of Section 21.(a)(i), LE GP, LLC, and, solely for the purpose of Section 1.1(b)(i), CenterPoint Energy, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed February 17, 2021)
2.3
Agreement and Plan of Merger, dated as of March 5, 2021, by and among Energy Transfer LP, ETO Merger Sub LLC and Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed March 5, 2021)
2.4
Agreement and Plan of Merger, dated as of April 1, 2021, by and among Energy Transfer Operating, L.P., Sunoco Logistics Partners Operations L.P. and Sunoco Logistics Partners GP LLC (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed April 2, 2021)
2.5
3.1
Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 to Form S-1 (File No. 333-128097) filed September 2, 2005)
3.1.1
Certificate of Amendment to Certificate of Limited Partnership of Energy Transfer LP (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed October 19, 2018)
3.2
Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed February 14, 2006)
3.3
Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 to Form 10-K (File No. 1-32740) filed November 29, 2006)
3.4
Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 to Form 8-K (File No. 1-32740) filed November 13, 2007)
3.5
Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed June 2, 2010)
3.6
Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed December 27, 2013)
3.7
Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of March 8, 2016 (incorporated by reference to Exhibit 3.1 to Form 8-K (File No. 1-32740) filed March 9, 2016)
3.8
Amendment No. 6 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No.1-32740, filed October 19, 2018 (incorporated by reference to Exhibit 3.2 to Form 8-K (File No. 1-32740) filed October 19, 2018)
3.9
Amendment No. 7 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP dated as of August 6, 2019 (incorporated by reference to Exhibit 3.10 to Form 10-Q (File No. 1-32740) filed August 8, 2019)
3.10
Amendment No. 8 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated April 1, 2021 (incorporated by reference to Exhibit 2.2 of Form 8-K (File No. 1-32740) filed April 1, 2021)
3.11
Amendment No. 9 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated June 15, 2021 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed June 15, 2021)
4.1
Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-32740) filed September 20, 2010)
159
Table of Contents
Exhibit
Number
Description
4.2
Fourth Supplemental Indenture, dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed December 2, 2013)
4.3
Fifth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed May 28, 2014)
4.4
Sixth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 1-32740) filed May 28, 2014)
4.5
Seventh Supplemental Indenture, dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed May 22, 2015)
4.6
Eighth Supplemental Indenture dated October 18, 2017 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed October 18th, 2017)
4.7
Ninth Supplemental Indenture, dated as of March 25, 2019, between Energy Transfer LP and U.S. Bank National Association as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed March 27, 2019)
4.8
Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-11727) filed January 19, 2005)
4.9
Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P, the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-11727) filed October 25, 2006)
4.10
Sixth Supplemental Indenture dated March 28, 2008, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed March 31, 2008)
4.11
Ninth Supplemental Indenture, dated as of May 12, 2011, to the Indenture dated January 18, 2005, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed May 12, 2011)
4.12
Tenth Supplemental Indenture, dated as of January 17, 2012, to the Indenture dated January 18, 2005, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed January 17, 2012)
4.13
Eleventh Supplemental Indenture dated as of January 22, 2013 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed January 23, 2013)
4.14
Twelfth Supplemental Indenture, dated as of January 24, 2013, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed June 26, 2013)
4.15
Thirteenth Supplemental Indenture, dated as of September 19, 2013, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed September 19, 2013)
4.16
Fourteenth Supplemental Indenture, dated as of March 12, 2015, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed March 12, 2015)
4.17
Fifteenth Supplemental Indenture, dated as of June 23, 2015, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 1-11727) filed June 23, 2015)
4.18
Sixteenth Supplemental Indenture, dated as of January 17, 2017, between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed January 17, 2017)
4.19
Seventeenth Supplemental Indenture, dated as of December 1, 2017, between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 10.8 to Form 8-K (File No. 1-31219) filed December 6, 2017)
4.20
Second Supplemental Indenture, dated December 1, 2017, among Energy Transfer Partners, L.P., and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.5 to Form 8-K (File No. 1-31219) filed December 6, 2017)
160
Table of Contents
Exhibit
Number
Description
4.21
Indenture, dated as of May 15, 1994, between Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A., relating to Sunoco, Inc.’s 9.00% Debentures due 2024 (incorporated by reference to Exhibit 4.8 to Form 8-K (File No. 1-31219) filed October 5, 2012)
4.22
First Supplemental Indenture, dated as of October 5, 2012, among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A., to the Indenture, dated as of May 15, 1994 (incorporated by reference to Exhibit 4.9 to Form 8-K (File No. 1-11727) filed October 5, 2012)
4.23
Sixteenth Supplemental Indenture, dated as of September 21, 2017, by and among Sunoco Logistics Partners Operations L.P., as issuer, Energy Transfer Partners, L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 to Form 8-K (File No. 1-31219) filed September 25, 2017)
4.24
Fifteenth Supplemental Indenture, dated as of September 21, 2017, by and among Sunoco Logistics Partners Operations L.P., as issuer, Energy Transfer Partners, L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-31219) filed September 25, 2017)
4.25
Third Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-31219) filed December 15, 2017)
4.26
Eighteenth Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-31219) filed December 15, 2017)
4.27
Tenth Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp., Sunoco Logistics Partners Operations L.P. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-31219) filed December 15, 2017)
4.28
Eleventh Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp., Sunoco Logistics Partners Operations L.P. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.4 to Form 8-K (File No. 1-31219) filed December 15, 2017)
4.29
Second Supplemental Indenture, dated as of December 1, 2017, by and between Energy Transfer Partners, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.6 to Form 8-K (File No. 1-31219) filed December 6, 2017)
4.30
Indenture, dated as of June 8, 2018, among Energy Transfer Partners, L.P. as issuer, Sunoco Logistics Partners Operations L.P., as guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-31219) filed June 8, 2018)
4.31
First Supplemental Indenture, dated as of June 8, 2018, by and among Energy Transfer Partners, L.P., as issuer, the subsidiary guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-31219) filed June 8, 2018)
4.32
Second Supplemental Indenture, dated as of January 15, 2019, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-31219) filed January 15, 2019)
4.33
Third Supplemental Indenture, dated as of March 25, 2019, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-31219) filed March 27, 2019)
4.34
Fourth Supplemental Indenture dated as of January 22, 2020, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary guarantors named therein, U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-31219) filed January 22, 2020)
4.35
Fifth Supplemental Indenture, dated as of December 28, 2021, by and among Energy Transfer LP, Enable Midstream Partners, LP and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-32740) filed December 28, 2021)
4.36
Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-36413) filed May 29, 2014)
4.37
First Supplemental Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, as issuer, CenterPoint Energy Resources Corp., as guarantor and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-36413) filed May 29, 2014)
4.38
Second Supplemental Indenture, dated as of March 9, 2017, by and among Enable Midstream Partners, LP, as issuer, CenterPoint Energy Resources Corp., as guarantor and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-36413) filed March 9, 2017)
161
Table of Contents
Exhibit
Number
Description
4.39
Third Supplemental Indenture, dated as of May 10, 2018, by and among Enable Midstream Partners, LP, as issuer, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-36413) filed May 10, 2018)
4.40
Fourth Supplemental Indenture, dated as of September 13, 2019, by and among Enable Midstream Partners, LP, as issuer, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-36413) filed September 13, 2019)
4.41
Indenture, dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee (incorporated by reference to Exhibit 4(a) to Form 10-Q (File No. 001-02921) filed May 15, 1999)
4.42
First Supplemental Indenture dated, as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee, including a form of Guarantee by Panhandle Eastern Pipe Line Company of the obligations of CMS Panhandle Holding Company (incorporated by reference to Exhibit 4(b) to Form 10-Q (File No. 001-02921) filed May 15, 1999)
4.43
Second Supplemental Indenture between Southern Union Company and The Bank of New York, N.A., as Trustee, dated as of October 23, 2006 (incorporated Second Supplemental Indenture between Southern Union Company and The Bank of New York, N.A., as Trustee, dated as of October 23, 2006 (incorporated by reference to Form 8-K/A (File No. 001-06407) filed October 26, 2006)
4.44
Third Supplemental Indenture, dated as of June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 001-06407) filed June 26, 2013)
4.45
Form of Sixth Supplemental Indenture, dated as of June 12, 2008, between PEPL and The Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-02921) filed June 11, 2008)
4.46
Form of Seventh Supplemental Indenture, to be dated as of June 2, 2009, between PEPL and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-02921) filed May 28, 2009)
4.47
Supplemental Indenture No. 3, dated as of June 24, 2013 between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-06407) filed June 26, 2013)
4.48
Supplemental Indenture No. 4, dated as of June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-06407) filed June 26, 2013)
4.49
Third Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed April 2, 2021)
4.50
Fourth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed April 2, 2021)
4.51
Fifth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-32740) filed April 2, 2021)
4.52
Seventeenth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association (incorporated by reference to Exhibit 10.4 to Form 8-K (File No. 1-32740) filed April 2, 2021)
4.53
Nineteenth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association (incorporated by reference to Exhibit 10.5 to Form 8-K (File No. 1-32740) filed April 2, 2021)
4.54
Eleventh Supplemental Indenture, dated April 1, 2021 by and between Energy Transfer LP, Regency Energy Finance Corp., and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.6 to Form 8-K (File No. 1-32740) filed April 2, 2021)
4.55
Twelfth Supplemental Indenture, dated April 1, 2021 by and between Energy Transfer LP, Regency Energy Finance Corp., and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.7 to Form 8-K (File No. 1-32740) filed April 2, 2021)
162
Table of Contents
Exhibit
Number
Description
4.56
Sixth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, as guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-11727) filed April 30, 2015)
4.57
Eighth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.4 to Form 8-K (File No. 1-11727) filed April 30, 2015)
4.58
Seventh Supplemental Indenture, dated as of May 28, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, Energy Transfer Partners, L.P., as co-obligor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-11727) filed June 1, 2015)
4.59
Eighth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-11727) filed August 13, 2015)
4.60
Ninth Supplemental Indenture, dated as of December 1, 2017 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.9 to Form 8-K (File No. 1-31219) filed December 6, 2017)
4.61
Ninth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-11727) filed August 13, 2015)
4.62
Tenth Supplemental Indenture, dated as of December 1, 2017, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.10 to Form 8-K (File No. 1-31219) filed December 6, 2017)
4.63
Supplemental Indenture No. 6, dated November 3, 2022, between Panhandle Eastern Pipe Line Company, LP, Energy Transfer LP and the Bank of New York Mellon Trust Company, as Trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-2921) filed November 17, 2022)
4.64
Fifth Supplemental Indenture, dated November 3, 2022, between Panhandle Eastern Pipe Line Company, LP, Energy Transfer LP and the Bank of New York Mellon Trust Company, as Trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-2921) filed November 17, 2022)
4.65
Eighth Supplemental Indenture, dated November 3, 2022, between Panhandle Eastern Pipe Line Company, LP, Energy Transfer LP and the Bank of New York Mellon Trust Company, as Trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-2921) filed November 17, 2022)
4.66
Indenture, dated as of December 14, 2022, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-32740) filed December 14, 2022)
4.67
First Supplemental Indenture, dated as of December 14, 2022, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed December 14, 2022)
4.68
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of Series C Preferred Units (incorporated by reference to Exhibit 4.43 to Form 10-K (File No. 1-32740) filed February 18, 2022)
4.69
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of Series D Preferred Units (incorporated by reference to Exhibit 4.44 to Form 10-K (File No. 1-32740) filed February 18, 2022)
4.70
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of Series E Preferred Units (incorporated by reference to Exhibit 4.45 to Form 10-K (File No. 1-32740) filed February 18, 2022)
4.71*
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of common units
10.1+
Amended and Restated Energy Transfer LP Long-Term Incentive Plan (formerly Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan) (incorporated by reference to Exhibit 10.1 to Form 10-K (File No. 1-32740) filed February 23, 2018)
10.2+
First Amendment to the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 10-K (File No. 1-32740) filed February 19, 2021)
10.3+
Second Amendment to the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed January 6, 2021)
163
Table of Contents
Exhibit
Number
Description
10.4+
Energy Transfer LP Long-Term Cash Restricted Unit Plan (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed January 6, 2021)
10.5+
Form of Cash Unit Award Agreement under the Energy Transfer LP Long-Term Cash Restricted Unit Plan (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-32740) filed January 6, 2021)
10.6+
Second Amended and Restated Energy Transfer LP 2008 Long-Term Incentive Plan (formerly Second Amended and Restated Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan) (incorporated by reference to Exhibit 4.1 to Form S-8 (File No. 333-229456) filed January 31, 2019)
10.7+
Energy Transfer LP 2011 Long-Term Incentive Plan (formerly Regency Energy Partners LP 2011 Long-Term Incentive Plan) (incorporated by reference to Exhibit 4.2 to Form S-8 (File No 333-229456) filed January 31, 2019)
10.8+
Energy Transfer LP 2015 Long-Term Incentive Plan, as amended and restated (formerly Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated) (incorporated by reference to Exhibit 4.3 to Form S-8 (File No. 333-229456) filed January 31, 2019)
10.9+
Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 to Form S-1 (File No. 333-128097) filed December 20, 2005)
10.10+
LE GP, LLC Amended and Restated Outside Director Compensation Policy (incorporated by reference to Exhibit 10.9 to Form 10-K (File No. 1-32740) filed February 22, 2019)
10.11+
Energy Transfer Deferred Compensation Plan (formerly called Energy Transfer Partners Deferred Compensation Plan) (incorporated by reference to Exhibit 10.1 to Form 10-Q (File No. 1-11727) filed May 7, 2010)
10.12+
10.13+
10.14+
Retention Agreement, by and among Energy Transfer Equity, L.P. and Thomas P. Mason, dated February 24, 2016 (incorporated by reference to Exhibit 10.21 to Form 10-K (File No. 1-32740) filed February 29, 2016)
10.15+
Energy Transfer LP Annual Bonus Plan (incorporated by reference to Exhibit 10.23 to Form 10-K (File No. 1-32740) filed February 22, 2019)
10.16
Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 1-32740) filed November 30, 2006)
10.17
Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 1-32740) filed March 5, 2007)
10.18
Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 to Form 8-K (File No. 1-32740) filed May 7, 2007)
10.19
Equity Restructuring Agreement, dated as of January 15, 2018, by and among Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression GP, LLC. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed January 16, 2018)
10.20
Registration Rights Agreement, dated as of April 2, 2018, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression Holdings, LLC. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed April 3, 2018)
10.21
Support Agreement, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC and CenterPoint Energy, Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed February 17, 2021)
10.22
Support Agreement, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC and OGE Energy Corp. (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed February 17, 2021)
10.23
Registration Rights Agreement, dated as of December 2, 2021, by and among Energy Transfer LP, CenterPoint Energy, Inc. and OGE Energy Corp. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed December 3, 2021)
10.24
Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.56 to Form 10-Q (File No. 1-11727) filed July 10, 2007)
10.25
Note Purchase Agreement, dated December 9, 2009, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-11727) filed December 14, 2009)
164
Table of Contents
Exhibit
Number
Description
10.26
Credit Agreement dated as of December 1, 2017 among Energy Transfer Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, the other lenders party thereto and the other parties named therein (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-31219) filed December 6, 2017)
10.27
Amendment No. 1 to Five-Year Credit Agreement, Joinder and Increase and Extension Agreement, dated as of October 19, 2018, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P., and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-31219) filed October 19, 2018)
10.28
Extension Agreement dated as of May 10, 2021 among Energy Transfer LP, the Consenting Lenders named therein, Wells Fargo Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed May 11, 2021)
10.29
Guarantee of Collection, dated as of April 30, 2013, by and between Regency Energy Partners LP, PEPL Holdings, LLC and Regency Energy Finance Corp. (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-11727) filed April 30. 2013)
10.30
Cushion Gas Litigation Agreement, dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-11727) filed February 1, 2005)
10.31
Guarantee of Collection, made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-11727) filed March 28, 2012)
10.32
Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P., and Citrus ETP Finance LLC (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-11727) filed March 28, 2012)
10.33
Form of Commercial Paper Dealer Agreement between Energy Transfer Partners, L.P., as Issuer, and the Dealer party thereto (incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 1-11727) filed August 22, 2016)
21.1*
List of Subsidiaries
22.1
Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 of Form 10-Q (File No. 1-32740) filed August 5, 2021)
23.1*
Consent of Grant Thornton LLP
31.1*
Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*
Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.3*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**
Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**
Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.3**
Certification Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101*Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements of Comprehensive Income (Loss); (iv) our Consolidated Statement of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements
104Cover Page Interactive Data File (embedded within the Inline XBRL document)
*Filed herewith.
**Furnished herewith.
+Denotes a management contract or compensatory plan or arrangement.
165
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENERGY TRANSFER LP
By:LE GP, LLC, its general partner
Date:February 17, 2023By:/s/ A. Troy Sturrock
A. Troy Sturrock
Group Senior Vice President, Controller and Principal Accounting
Officer (duly authorized to sign on behalf of the registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
SignatureTitleDate
/s/ Kelcy L. WarrenExecutive ChairmanFebruary 17, 2023
Kelcy L. Warren
/s/ Marshall S. McCrea, IIICo-Chief Executive Officer and DirectorFebruary 17, 2023
Marshall S. McCrea, III(Co-Principal Executive Officer)
/s/ Thomas E. LongCo-Chief Executive Officer and DirectorFebruary 17, 2023
Thomas E. Long(Co-Principal Executive Officer)
/s/ Dylan A. BramhallGroup Chief Financial OfficerFebruary 17, 2023
Dylan A. Bramhall(Principal Financial Officer)
/s/ A. Troy SturrockGroup Senior Vice President and ControllerFebruary 17, 2023
A. Troy Sturrock(Principal Accounting Officer)
/s/ Steven R. AndersonDirectorFebruary 17, 2023
Steven R. Anderson
/s/ Richard D. BrannonDirectorFebruary 17, 2023
Richard D. Brannon
/s/ Michael K. GrimmDirectorFebruary 17, 2023
Michael K. Grimm
/s/ John W. McReynoldsDirectorFebruary 17, 2023
John W. McReynolds
/s/ James R. PerryDirectorFebruary 17, 2023
James R. Perry
/s/ Matthew S. RamseyDirectorFebruary 17, 2023
Matthew S. Ramsey
166
INDEX TO FINANCIAL STATEMENTS
Energy Transfer LP and Subsidiaries
Page
F - 2
F - 4
F - 6
F - 7
F - 8
F - 9
F - 10
1.Operations and Basis of Presentation
F - 10
2. Estimates, Significant Accounting Policies and Balance Sheet Detail
F - 11
3. Acquisitions, Divestitures and Related Transactions
F - 23
4. Investments in Unconsolidated Affiliates
F - 24
5. Net Income Per Common Unit
F - 26
6. Debt Obligations
F - 27
7. Redeemable Noncontrolling Interests
F - 32
8. Equity
F - 33
9. Equity Incentive Plans
F - 39
10. Income Taxes
F - 40
11. Regulatory Matters, Commitments, Contingencies and Environmental Liabilities
F - 43
12. Revenue
F - 52
13. Lease Accounting
F - 59
14. Derivative Assets and Liabilities
F - 62
15. Retirement Benefits
F - 66
16. Reportable Segments
F - 70
F - 1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer LP
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P.LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 20172022 and 2016,2021, the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2017,2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 20172022 and 2016,2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2022, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017,2022, based on criteria established in the 2013 Internal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018 (not separately included herein)17, 2023 expressed an unqualified opinion thereon.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.opinion.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Goodwill Impairment Assessment
As described further in Note 2 to the consolidated financial statements, the Partnership’s consolidated goodwill balance was $2.6 billion as of December 31, 2022. Management evaluates goodwill for impairment annually on October 1st of each year or whenever events or changes in circumstances indicate potential asset impairment has occurred. As of December 31, 2022, there was $368 million of goodwill associated with a reporting unit within the NGL and Refined Products Transportation and Services segment in which we identified the Partnership’s determination of the fair value of the reporting unit as a critical audit matter.

The principal considerations for our determination that the estimation of the fair value of the reporting unit is a critical audit matter are that there are significant judgments required by management when determining the fair value of the reporting unit. In particular, the fair value estimate was sensitive to significant assumptions used to estimate future revenues and cash flows, including revenue growth rates, operating expenses, discount rate, and the inherent uncertainty around future market conditions as well as valuation methodologies applied by the Partnership.

Our audit procedures related to the determination that the estimation of the fair value of the reporting unit included the following, among others. We tested the effectiveness of controls relating to management’s review of the assumptions used to develop the future cash flows, the discount rate used, and valuation methodologies applied. In addition to testing the effectiveness of controls, we also performed the following:
F - 2
a.Evaluated the reasonableness of management’s forecasted financial results by:
i.Assessing the reasonableness of management’s forecast of future projected results by comparing such items to industry projections and conditions found in industry reports,
ii.Testing forecasted revenues and expected future cash flows by comparing forecasted amounts to actual historical results to identify material changes, corroborating the basis for increases in forecasted revenues and expected future cash flows, as applicable, and
iii.Testing significant operating expenses and cash expenditures by comparing to historical trends and evaluating significant deviations from recent actual amounts.
b.Utilized an internal valuation specialist to evaluate:
i.The methodologies used and whether they were acceptable for the underlying assets or operations and whether such methodologies were being applied correctly, and
ii.The appropriateness of the discount rate by developing an independent range of acceptable discount rates and comparing those ranges to the amounts selected and applied by management.



/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2004.


Dallas, Texas
February 23, 201817, 2023

F - 3

ENERGY TRANSFER PARTNERS, L.P.LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
December 31,
20222021
ASSETS
Current assets:
Cash and cash equivalents$257 $336 
Accounts receivable, net8,466 7,654 
Accounts receivable from related companies93 54 
Inventories2,461 2,014 
Income taxes receivable68 32 
Derivative assets10 10 
Other current assets726 437 
Total current assets12,081 10,537 
Property, plant and equipment105,996 103,991 
Accumulated depreciation and depletion(25,685)(22,384)
   Property, plant and equipment, net80,311 81,607 
Investments in unconsolidated affiliates2,893 2,947 
Lease right-of-use assets, net819 838 
Other non-current assets, net1,558 1,645 
Intangible assets, net5,415 5,856 
Goodwill2,566 2,533 
Total assets$105,643 $105,963 
The accompanying notes are an integral part of these consolidated financial statements.
F - 4
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$306
 $360
Accounts receivable, net3,946
 3,002
Accounts receivable from related companies318
 209
Inventories1,589
 1,626
Income taxes receivable135
 128
Derivative assets24
 20
Other current assets210
 298
Total current assets6,528
 5,643
    
Property, plant and equipment67,699
 58,220
Accumulated depreciation and depletion(9,262) (7,303)
 58,437
 50,917
    
Advances to and investments in unconsolidated affiliates3,816
 4,280
Other non-current assets, net758
 672
Intangible assets, net5,311
 4,696
Goodwill3,115
 3,897
Total assets$77,965
 $70,105
* As adjusted. See Note 2.Index to Financial Statements

ENERGY TRANSFER PARTNERS, L.P.LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Dollars in millions)
December 31,
20222021
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$6,952 $6,834 
Accounts payable to related companies17 — 
Derivative liabilities23 203 
Operating lease current liabilities45 47 
Accrued and other current liabilities3,329 3,071 
Current maturities of long-term debt2 680 
Total current liabilities10,368 10,835 
Long-term debt, less current maturities48,260 49,022 
Non-current derivative liabilities23 193 
Non-current operating lease liabilities798 814 
Deferred income taxes3,701 3,648 
Other non-current liabilities1,341 1,323 
Commitments and contingencies
Redeemable noncontrolling interests493 783 
Equity:
Limited Partners:
Preferred Unitholders (72,184,780 and 72,184,780 units authorized, issued and outstanding as of December 31, 2022 and 2021, respectively)6,051 6,051 
Common Unitholders (3,094,445,367 and 3,082,517,494 units authorized, issued and outstanding as of December 31, 2022 and 2021, respectively)26,960 25,230 
General Partner(2)(4)
Accumulated other comprehensive income16 23 
Total partners’ capital33,025 31,300 
Noncontrolling interests7,634 8,045 
Total equity40,659 39,345 
Total liabilities and equity$105,643 $105,963 
The accompanying notes are an integral part of these consolidated financial statements.
F - 5
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,126
 $2,900
Accounts payable to related companies209
 43
Derivative liabilities109
 166
Accrued and other current liabilities2,143
 1,905
Current maturities of long-term debt407
 1,189
Total current liabilities6,994
 6,203
    
Long-term debt, less current maturities32,687
 31,741
Long-term notes payable – related company—
 250
Non-current derivative liabilities145
 76
Deferred income taxes2,883
 4,394
Other non-current liabilities1,084
 952
    
Commitments and contingencies
 

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

ENERGY TRANSFER PARTNERS, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
Years Ended December 31,
 202220212020
REVENUES:
Refined product sales$26,020 $17,766 $10,514 
Crude sales23,473 15,299 9,442 
NGL sales20,114 15,243 6,797 
Gathering, transportation and other fees10,907 9,229 8,982 
Natural gas sales8,535 9,159 2,633 
Other827 721 586 
Total revenues89,876 67,417 38,954 
COSTS AND EXPENSES:
Cost of products sold72,232 50,395 25,487 
Operating expenses4,338 3,574 3,218 
Depreciation, depletion and amortization4,164 3,817 3,678 
Selling, general and administrative1,018 818 711 
Impairment losses and other386 21 2,880 
Total costs and expenses82,138 58,625 35,974 
OPERATING INCOME7,738 8,792 2,980 
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized(2,306)(2,267)(2,327)
Equity in earnings of unconsolidated affiliates257 246 119 
Impairment of investments in unconsolidated affiliates— — (129)
Losses on extinguishments of debt— (38)(75)
Gains (losses) on interest rate derivatives293 61 (203)
Other, net90 77 12 
INCOME BEFORE INCOME TAX EXPENSE6,072 6,871 377 
Income tax expense204 184 237 
NET INCOME5,868 6,687 140 
Less: Net income attributable to noncontrolling interests1,061 1,167 739 
Less: Net income attributable to redeemable noncontrolling interests51 50 49 
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS4,756 5,470 (648)
General Partner’s interest in net income (loss)4 6 (1)
Preferred Unitholders’ interest in net income422 285 — 
Common Unitholders’ interest in net income (loss)$4,330 $5,179 $(647)
NET INCOME (LOSS) PER COMMON UNIT:
Basic$1.40 $1.89 $(0.24)
Diluted$1.40 $1.89 $(0.24)
The accompanying notes are an integral part of these consolidated financial statements.
F - 6
 Years Ended December 31,
 2017 2016* 2015*
REVENUES:     
Natural gas sales$4,172
 $3,619
 $3,671
NGL sales6,972
 4,841
 3,936
Crude sales10,184
 6,766
 8,378
Gathering, transportation and other fees4,265
 4,003
 3,997
Refined product sales (see Note 3)1,515
 1,047
 9,958
Other (see Note 3)1,946
 1,551
 4,352
Total revenues29,054
 21,827
 34,292
COSTS AND EXPENSES:     
Cost of products sold (see Note 3)20,801
 15,080
 26,714
Operating expenses (see Note 3)2,170
 1,839
 2,608
Depreciation, depletion and amortization2,332
 1,986
 1,929
Selling, general and administrative (see Note 3)434
 348
 475
Impairment losses920
 813
 339
Total costs and expenses26,657
 20,066
 32,065
OPERATING INCOME2,397
 1,761
 2,227
OTHER INCOME (EXPENSE):     
Interest expense, net(1,365) (1,317) (1,291)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Gains on acquisitions—
 83
 —
Losses on extinguishments of debt(42) —
 (43)
Losses on interest rate derivatives(37) (12) (18)
Other, net209
 131
 22
INCOME BEFORE INCOME TAX BENEFIT1,005
 397
 1,366
Income tax benefit(1,496) (186) (123)
NET INCOME2,501
 583
 1,489
Less: Net income attributable to noncontrolling interest420
 295
 134
Less: Net loss attributable to predecessor—
 —
 (34)
NET INCOME ATTRIBUTABLE TO PARTNERS2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)$986
 $(1,019) $(27)
NET INCOME (LOSS) PER COMMON UNIT:     
Basic$0.94
 $(1.38) $(0.07)
Diluted$0.93
 $(1.38) $(0.08)
* As adjusted. See Note 2.Index to Financial Statements

ENERGY TRANSFER PARTNERS, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Years Ended December 31,
 202220212020
Net income$5,868 $6,687 $140 
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities(10)1 5 
Actuarial gain (loss) relating to pension and other postretirement benefits(12)12 18 
Foreign currency translation adjustment(6)4 5 
Change in other comprehensive income from unconsolidated affiliates24 3 (13)
(4)20 15 
Comprehensive income5,864 6,707 155 
Less: Comprehensive income attributable to noncontrolling interests1,055 1,170 738 
Less: Comprehensive income attributable to redeemable noncontrolling interests51 50 49 
Comprehensive income (loss) attributable to partners$4,758 $5,487 $(632)
The accompanying notes are an integral part of these consolidated financial statements.
F - 7
 Years Ended December 31,
 2017 2016* 2015*
Net income$2,501
 $583
 $1,489
Other comprehensive income (loss), net of tax:     
Change in value of available-for-sale securities6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(12) (1) 65
Foreign currency translation adjustment—
 (1) (1)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
 (5) 4
 60
Comprehensive income2,496
 587
 1,549
Less: Comprehensive income attributable to noncontrolling interest420
 295
 134
Less: Comprehensive loss attributable to predecessor—
 —
 (34)
Comprehensive income attributable to partners$2,076
 $292
 $1,449
* As adjusted. See Note 2.Index to Financial Statements

ENERGY TRANSFER PARTNERS, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
Common
Unitholders		Preferred UnitholdersGeneral
Partner		Accumulated
Other
Comprehensive
Income (Loss)		Non-
controlling
Interests		Total
Balance, December 31, 2019$21,935 $— $(4)$(11)$12,018 $33,938 
Distributions to partners(2,799)— (3)— — (2,802)
Distributions to noncontrolling interests— — — — (1,651)(1,651)
Subsidiary units issued— — — — 1,580 1,580 
Capital contributions from noncontrolling interests— — — — 222 222 
Other comprehensive income (loss), net of tax— — — 16 (1)15 
Other, net42 — — 1 (48)(5)
Net income (loss), excluding amounts attributable to redeemable noncontrolling interests(647)— (1)— 739 91 
Balance, December 31, 202018,531 — (8)6 12,859 31,388 
Preferred units converted in Rollup Mergers— 4,768 — — (4,768)— 
Distributions to partners(1,616)(280)(2)— — (1,898)
Distributions to noncontrolling interests— — — — (1,487)(1,487)
Common units repurchased(31)— — — — (31)
Units issued— 889 — — — 889 
Capital contributions from noncontrolling interests— — — — 226 226 
Enable Acquisition3,117 392 — — 34 3,543 
Other comprehensive income, net of tax— — — 17 3 20 
Other, net50 (3)— — 11 58 
Net income, excluding amounts attributable to redeemable noncontrolling interests5,179 285 6 — 1,167 6,637 
Balance, December 31, 202125,230 6,051 (4)23 8,045 39,345 
Distributions to partners(2,623)(422)(2)— — (3,047)
Distributions to noncontrolling interests— — — — (1,547)(1,547)
Capital contributions from noncontrolling interests— — — — 405 405 
Energy Transfer Canada sale— — — (9)(337)(346)
Other comprehensive income (loss), net of tax— — — 2 (6)(4)
Other, net23 — — — 13 36 
Net income, excluding amounts attributable to redeemable noncontrolling interests4,330 422 4 — 1,061 5,817 
Balance, December 31, 2022$26,960 $6,051 $(2)$16 $7,634 $40,659 
The accompanying notes are an integral part of these consolidated financial statements.
F - 8
     Limited Partners          
 Series A Preferred Units Series B Preferred Units Common Unit holders Class H Units Class I Units General
Partner		 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-controlling
Interest
 Predecessor Equity Total
Balance, December 31, 2014*$—
 $—
 $10,427
 $1,512
 $—
 $184
 $(56) $5,143
 $8,088
 $25,298
Distributions to partners—
 —
 (1,863) (247) (80) (944) —
 —
 —
 (3,134)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (338) —
 (338)
Units issued for cash—
 —
 1,428
 —
 —
 —
 —
 —
 —
 1,428
Subsidiary units issued for cash—
 —
 298
 —
 —
 2
 —
 1,219
 —
 1,519
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 875
 —
 875
Bakken Pipeline Transaction—
 —
 (999) 1,946
 —
 —
 —
 72
 —
 1,019
Sunoco LP Exchange Transaction—
 —
 (52) —
 —
 —
 —
 (940) —
 (992)
Susser Exchange Transaction—
 —
 (68) —
 —
 —
 —
 —
 —
 (68)
Acquisition and disposition of noncontrolling interest—
 —
 (26) —
 —
 —
 —
 (39) —
 (65)
Predecessor distributions to partners—
 —
 —
 —
 —
 —
 —
 —
 (202) (202)
Predecessor units issued for cash—
 —
 —
 —
 —
 —
 —
 —
 34
 34
Regency Merger—
 —
 7,890
 —
 —
 —
 —
 —
 (7,890) —
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 60
 —
 —
 60
Other, net—
 —
 23
 —
 —
 —
 —
 36
 4
 63
Net income (loss)—
 —
 (27) 258
 94
 1,064
 —
 134
 (34) 1,489
Balance, December 31, 2015*—
 —
 17,031
 3,469
 14
 306
 4
 6,162
 —
 26,986
Distributions to partners—
 —
 (2,134) (340) (20) (1,048) —
 —
 —
 (3,542)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (481) —
 (481)
Units issued for cash—
 —
 1,098
 —
 —
 —
 —
 —
 —
 1,098
Subsidiary units issued—
 —
 37
 —
 —
 —
 —
 1,351
 —
 1,388
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 236
 —
 236
Sunoco, Inc. retail business to Sunoco LP transaction—
 —
 (405) —
 —
 —
 —
 —
 —
 (405)
PennTex Acquisition—
 —
 307
 —
 —
 —
 —
 236
 —
 543
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 4
 —
 —
 4
Other, net—
 —
 10
 —
 —
 —
 —
 21
 —
 31
Net income (loss)—
 —
 (1,019) 351
 8
 948
 —
 295
 —
 583
Balance, December 31, 2016*—
 —
 14,925
 3,480
 2
 206
 8
 7,820
 —
 26,441
Distributions to partners—
 —
 (2,419) (95) (2) (952) —
 —
 —
 (3,468)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (430) —
 (430)
Units issued for cash937
 542
 2,283
 —
 —
 —
 —
 —
 —
 3,762
Sunoco Logistics Merger—
 —
 9,416
 (3,478) —
 —
 —
 (5,938) —
 —
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 2,202
 —
 2,202
Sale of Bakken Pipeline interest—
 —
 1,260
 —
 —
 —
 —
 740
 —
 2,000
Sale of Rover Pipeline interest—
 —
 93
 —
 —
 —
 —
 1,385
 —
 1,478
Acquisition of PennTex noncontrolling interest—
 —
 (48) —
 —
 —
 —
 (232) —
 (280)
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 —
 (5) —
 —
 (5)
Other, net—
 —
 35
 —
 —
 —
 —
 (85) —
 (50)
Net income7
 5
 986
 93
 —
 990
 —
 420
 —
 2,501
Balance, December 31, 2017$944
 $547
 $26,531
 $—
 $—
 $244
 $3
 $5,882
 $—
 $34,151
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
Years Ended December 31,
202220212020
OPERATING ACTIVITIES:
Net income$5,868 $6,687 $140 
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization4,164 3,817 3,678 
Deferred income taxes187 141 210 
Inventory valuation adjustments(5)(190)82 
Non-cash compensation expense115 111 121 
Impairment losses386 21 2,880 
Impairment of investment in unconsolidated affiliates— — 129 
Losses on extinguishments of debt— 38 75 
Distributions on unvested awards(73)(47)(41)
Equity in earnings of unconsolidated affiliates(257)(246)(119)
Distributions from unconsolidated affiliates232 212 220 
Other non-cash(64)103 (61)
Net change in operating assets and liabilities, net of effects of acquisitions(1,502)515 47 
Net cash provided by operating activities9,051 11,162 7,361 
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received(1,141)(205)— 
Capital expenditures, excluding allowance for equity funds used during construction(3,381)(2,822)(5,130)
Contributions in aid of construction costs56 43 67 
Contributions to unconsolidated affiliates— (4)(38)
Distributions from unconsolidated affiliates in excess of cumulative earnings62 167 187 
Proceeds from sale of Energy Transfer Canada interest302 — — 
Proceeds from sales of other assets78 45 19 
Other2 1 (3)
Net cash used in investing activities(4,022)(2,775)(4,898)
FINANCING ACTIVITIES:
Proceeds from borrowings28,838 21,267 24,440 
Repayments of debt(29,681)(27,318)(24,133)
Preferred units issued for cash— 889 — 
Subsidiary units issued for cash— — 1,580 
Capital contributions from noncontrolling interests405 226 222 
Distributions to partners(3,047)(1,898)(2,802)
Distributions to noncontrolling interests(1,547)(1,487)(1,651)
Distributions to redeemable noncontrolling interests(49)(49)(49)
Common units repurchased under buyback program— (31)— 
Debt issuance costs(27)(14)(59)
Other— (3)65 
Net cash used in financing activities(5,108)(8,418)(2,387)
Increase (decrease) in cash and cash equivalents(79)(31)76 
Cash and cash equivalents, beginning of period336 367 291 
Cash and cash equivalents, end of period$257 $336 $367 
The accompanying notes are an integral part of these consolidated financial statements.
F - 9
 Years Ended December 31,
 2017 2016* 2015*
OPERATING ACTIVITIES:     
Net income$2,501
 $583
 $1,489
Reconciliation of net income to net cash provided by operating activities:     
Depreciation, depletion and amortization2,332
 1,986
 1,929
Deferred income taxes(1,531) (169) 202
Amortization included in interest expense2
 (20) (36)
Inventory valuation adjustments—
 —
 (58)
Unit-based compensation expense74
 80
 79
Impairment losses920
 813
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt42
 —
 43
Impairment of investments in unconsolidated affiliates313
 308
 —
Distributions on unvested awards(31) (25) (16)
Equity in earnings of unconsolidated affiliates(156) (59) (469)
Distributions from unconsolidated affiliates440
 406
 440
Other non-cash(261) (271) (22)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(160) (246) (1,173)
Net cash provided by operating activities4,485
 3,303
 2,747
INVESTING ACTIVITIES:     
Cash proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Cash proceeds from sale of Rover Pipeline interest1,478
 —
 —
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction—
 2,200
 —
Proceeds from Bakken Pipeline Transaction—
 —
 980
Proceeds from Susser Exchange Transaction—
 —
 967
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Cash paid for Vitol Acquisition, net of cash received—
 (769) —
Cash paid for PennTex Acquisition, net of cash received—
 (299) —
Cash transferred to ETE in connection with the Sunoco LP Exchange—
 —
 (114)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Cash paid for all other acquisitions(264) (159) (675)
Capital expenditures, excluding allowance for equity funds used during construction(8,335) (7,550) (9,098)
Contributions in aid of construction costs24
 71
 80
Contributions to unconsolidated affiliates(268) (59) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings136
 135
 124
Proceeds from the sale of assets35
 25
 23
Change in restricted cash—
 14
 19
Other1
 1
 (16)
Net cash used in investing activities(5,473) (6,390) (7,820)
      
FINANCING ACTIVITIES:     
Proceeds from borrowings26,736
 19,916
 22,462
Repayments of long-term debt(26,494) (15,799) (17,843)
Cash (paid to) received from affiliate notes(255) 124
 233
Common Units issued for cash2,283
 1,098
 1,428
Preferred Units issued for cash1,479
 —
 —
Subsidiary units issued for cash—
 1,388
 1,519
Predecessor units issued for cash—
 —
 34
Capital contributions from noncontrolling interest1,214
 236
 841
Distributions to partners(3,468) (3,542) (3,134)
Predecessor distributions to partners—
 —
 (202)
Distributions to noncontrolling interest(430) (481) (338)
Redemption of Legacy ETP Preferred Units(53) —
 —
Debt issuance costs(83) (22) (63)
Other5
 2
 —
Net cash provided by financing activities934
 2,920
 4,937
Decrease in cash and cash equivalents(54) (167) (136)
Cash and cash equivalents, beginning of period360
 527
 663
Cash and cash equivalents, end of period$306
 $360
 $527
* As adjusted. See Note 2.




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

1.OPERATIONS AND BASIS OF PRESENTATION:
Organization. 1.OPERATIONS AND BASIS OF PRESENTATION:
The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P.LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”“Energy Transfer”).
On April 1, 2021, Energy Transfer, ETO and certain of ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC,In connection with the general partner of our General Partner.
In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner wasRollup Mergers, ETO merged with and into ETP GP,Energy Transfer, with ETP GP survivingEnergy Transfer surviving. The impacts of the Rollup Mergers also included the following:
•All of ETO’s long-term debt was assumed by Energy Transfer, as an indirect wholly-owned subsidiarymore fully described in Note 6.
•Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created Energy Transfer preferred unit. A description of ETE. In connection with the merger, the ETPEnergy Transfer Preferred Units is included in Note 8.
•Each of ETO’s issued and outstanding Class H units were cancelled. The outstanding ETPK, Class E units,L, Class G units, Class I unitsM and Class KN units at the effective time of the merger were converted into an equal number ofaggregate 675,625,000 newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closingClass B Units representing limited partner interests in Energy Transfer. All of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units ownedUnits are held by ETP at the effective timeHoldco, a wholly-owned subsidiary of the merger were cancelled.Energy Transfer.
In connection with the Sunoco Logistics Merger,November 2022, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The Sunoco Logistics MergerPanhandle completed an internal reorganization which resulted in Energy Transfer Partners, L.P. being treatedassuming all of Panhandle’s notes and debentures, as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidatedmore fully discussed in Note 6.
Our financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the mergerfollowing reportable segments:
•intrastate transportation and name changes).storage;
•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP;
•investment in USAC; and
•all other.
The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assetsPartnership owns and liabilitiesoperates intrastate natural gas pipeline systems and storage facilities that are engaged in the consolidated financial statements,business of purchasing, gathering, transporting, processing and no gain or loss was recognized. Formarketing natural gas and NGLs in the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.states of Texas, Oklahoma and Louisiana.
The historical common unitsPartnership owns and net income (loss) per limited partner unit amounts presentedoperates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.United States.
The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Permian, Anadarko, Arkoma and Hugoton basins, as well as the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus Utica, Bone Spring and AvalonUtica shales.
The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.
The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership owns a controlling interest in Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. As of December 31, 2022, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as well as 28.5 million common units.
The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. As of December 31, 2022, our interest in USAC consisted of 100% of the general partner and 46.1 million common units.
F - 10
Basis of Presentation.The consolidated financial statements of Energy Transfer LP presented herein for the Partnershipyears ended December 31, 2022, 2021 and 2020, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation.
The consolidated financial statements of Energy Transfer presented herein include the accountsresults of alloperations of our controlled subsidiaries, after the elimination of all intercompany accountsincluding Sunoco LP and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued.USAC.
For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.
The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately.
2.ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Change in Accounting Policy
During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

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

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

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

Regulatory Accounting – Regulatory Assets and Liabilities
Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities.authorities, in accordance with Accounting Standards Codification (“ASC”) Topic 980. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment under ASC Topic 980 for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938NGA and Natural Gas Policy Act of 1978, itNGPA, Panhandle does not currently apply regulatory accounting policiesASC Topic 980 in accounting for its operations.  Panhandle does not apply regulatory accounting policiesGAAP-basis consolidated financial statements, primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
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The net change in operating assets and liabilities, (netnet of effects of acquisitions, and deconsolidations) included in cash flows from operating activities is comprised as follows:
Years Ended December 31, Years Ended December 31,
2017 2016 2015 202220212020
Accounts receivable$(950) $(919) $819
Accounts receivable$(863)$(3,356)$1,163 
Accounts receivable from related companies67
 30
 (243)Accounts receivable from related companies23 38 (290)
Inventories37
 (497) (157)Inventories(361)(19)(271)
Other current assets39
 83
 (178)Other current assets(326)(216)172 
Other non-current assets, net(94) (78) 188
Other non-current assets, net146 1 (7)
Accounts payable758
 972
 (1,215)Accounts payable25 3,834 (1,327)
Accounts payable to related companies(3) 29
 (160)Accounts payable to related companies6 (34)367 
Accrued and other current liabilities(47) 39
 (83)Accrued and other current liabilities131 238 163 
Other non-current liabilities24
 33
 (219)Other non-current liabilities66 117 8 
Price risk management assets and liabilities, net9
 62
 75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$(160) $(246) $(1,173)
Derivative assets and liabilities, netDerivative assets and liabilities, net(349)(88)69 
Net change in operating assets and liabilities, net of effects of acquisitionsNet change in operating assets and liabilities, net of effects of acquisitions$(1,502)$515 $47 
Non-cash investing and financing activities and supplemental cash flow information are as follows:
 Years Ended December 31,
 202220212020
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures$575 $464 $604 
Units issued in connection with the Enable Acquisition(1)
— 3,509 — 
Lease assets obtained in exchange for new lease liabilities42 18 42 
Acquisition of interest in unconsolidated affiliate— 49 — 
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized$2,167 $2,188 $2,092 
Cash paid for income taxes (net of refunds)54 41 (64)
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,059
 $822
 $896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP—
 194
 —
Net gains from subsidiary common unit transactions—
 37
 300
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Issuance of Common Units in connection with the Regency Merger—
 —
 9,250
Issuance of Class H Units in connection with the Bakken Pipeline Transaction—
 —
 1,946
Contribution of assets from noncontrolling interest988
 —
 34
Redemption of Common Units in connection with the Bakken Pipeline Transaction—
 —
 999
Redemption of Common Units in connection with the Sunoco LP Exchange—
 —
 52
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,329
 $1,411
 $1,467
Cash paid for (refund of) income taxes50
 (229) 71
(1)See Note 3 for additional information.
Accounts Receivable
Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not.sector. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.
We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment.sector. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accountscredit losses on trade receivables based on the expected ultimate recovery of these receivables and considersconsider many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. IncreasesChanges in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.
We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

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Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2022 and 2021, Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $116 million and $121 million, respectively. For the years ended December 31, 2022, 2021 and 2020, the Partnership’s consolidated statements of operations and comprehensive income did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the years ended December 31, 2022 and 2021, the Partnership’s cost of products sold included favorable inventory adjustments of $5 million and $190 million, respectively, and for year ended December 31, 2020, an unfavorable inventory adjustment of $82 million, related to Sunoco LP’s LIFO inventory.
The Partnership’s inventories consisted of the following:
December 31,
December 31, 20222021
2017 2016
Natural gas, NGLs, and refined products$733
 $758
Natural gas, NGLs and refined productsNatural gas, NGLs and refined products$1,802 $1,259 
Crude oil551
 651
Crude oil246 328 
Spare parts and other305
 217
Spare parts and other413 427 
Total inventories$1,589
 $1,626
Total inventories$2,461 $2,014 
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Other Current Assets
Other current assets consisted of the following:
December 31, December 31,
2017 2016 20222021
Deposits paid to vendors$64
 $74
Deposits paid to vendors$334 $215 
Prepaid expenses and other146
 224
Prepaid expenses and other392 222 
Total other current assets$210
 $298
Total other current assets$726 $437 
Property, Plant and Equipment
Property, plant and equipment areis stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandatedFERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment areis retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017,2022 and 2021, USAC recognized fixed asset impairments of $1 million and $5 million, respectively, related to its compression equipment as a result of its evaluation of the future deployment of idle fleet.
In 2020, the Partnership recordedrecognized a $127$58 million fixed asset impairment related to Sea Robin primarily due to a reductiondecreases in expectedprojected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as wellflow as a $10result of the overall market demand decline. In addition, USAC recorded an $8 million impairment to property, plant andof compression equipment inas a result of its evaluations of the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.deployment of its idle fleet.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilityfacilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the
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capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:
December 31, December 31,
2017 2016 20222021
Land and improvements$1,706
 $676
Land and improvements$1,427 $1,369 
Buildings and improvements (1 to 45 years)1,960
 1,617
Buildings and improvements (1 to 45 years)3,546 4,598 
Pipelines and equipment (5 to 83 years)44,050
 36,356
Pipelines and equipment (5 to 83 years)82,353 77,112 
Natural gas and NGL storage facilities (5 to 46 years)1,681
 1,452
Bulk storage, equipment and facilities (2 to 83 years)3,036
 3,701
Vehicles (1 to 25 years)124
 217
Product storage and related facilities (2 to 83 years)Product storage and related facilities (2 to 83 years)7,274 7,410 
Right of way (20 to 83 years)3,424
 3,349
Right of way (20 to 83 years)6,252 5,021 
Natural resources434
 434
Other (1 to 40 years)534
 484
Other (1 to 48 years)Other (1 to 48 years)2,739 2,816 
Construction work-in-process10,750
 9,934
Construction work-in-process2,405 5,665 
67,699
 58,220
105,996 103,991 
Less – Accumulated depreciation and depletion(9,262) (7,303)Less – Accumulated depreciation and depletion(25,685)(22,384)
Property, plant and equipment, net$58,437
 $50,917
Property, plant and equipment, net$80,311 $81,607 
We recognized the following amounts for the periods presented:
 Years Ended December 31,
 202220212020
Depreciation, depletion and amortization expense$3,774 $3,465 $3,275 
Capitalized interest112 135 189 
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,060
 $1,793
 $1,713
Capitalized interest283
 199
 163
Advances to and Investments in Unconsolidated Affiliates
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. During the year ended December 31, 2020, the Partnership recorded an impairment of its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
 December 31,
 2017 2016
Regulatory assets$85
 $86
Deferred charges210
 217
Restricted funds192
 190
Long-term affiliated receivable85
 90
Other186
 89
Total other non-current assets, net$758
 $672
(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
December 31,
20222021
Crude pipeline linefill and tank bottoms$489 $498 
Regulatory assets55 42 
Pension assets129 140 
Deferred charges140 177 
Restricted funds121 164 
Other624 624 
Total other non-current assets, net$1,558 $1,645 
Restricted funds primarily consistedinclude an immaterial amount of restricted cash primarily held in our wholly-owned captive insurance companies.

F - 14
Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
December 31, 2017 December 31, 2016 December 31, 2022December 31, 2021
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Gross Carrying
Amount		Accumulated
Amortization		Gross Carrying
Amount		Accumulated
Amortization
Amortizable intangible assets:       Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)$6,250
 $(1,003) $5,362
 $(737)Customer relationships, contracts and agreements (3 to 46 years)$7,884 $(2,807)$7,982 $(2,464)
Patents (10 years)48
 (26) 48
 (21)Patents (10 years)48 (48)48 (44)
Trade Names (20 years)66
 (25) 66
 (22)
Trade names (20 years)Trade names (20 years)66 (41)66 (38)
Other (5 to 20 years)1
 —
 2
 (2)Other (5 to 20 years)12 (13)19 (20)
Total amortizable intangible assetsTotal amortizable intangible assets8,010 (2,909)8,115 (2,566)
Non-amortizable intangible assets:Non-amortizable intangible assets:
TrademarksTrademarks302 — 295 — 
OtherOther12 — 12 — 
Total non-amortizable intangible assetsTotal non-amortizable intangible assets314 — 307 — 
Total intangible assets$6,365
 $(1,054) $5,478
 $(782)Total intangible assets$8,324 $(2,909)$8,422 $(2,566)
Aggregate amortization expense of intangible assets was as follows:
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$272
 $193
 $216
Years Ended December 31,
202220212020
Reported in depreciation, depletion and amortization expense$390 $352 $403 
Estimated aggregate amortization expenseof intangible assets for the next five years is as follows:
Years Ending December 31: 
2018$280
2019278
2020278
2021268
2022256
Years Ending December 31: 
2023$357 
2024344 
2025331 
2026327 
2027309 
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
In 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test iswas performed during the fourth quarter.

F - 15
Changes in the carrying amount of goodwill were as follows:
Intrastate
Transportation
and Storage		Interstate
Transportation and Storage		MidstreamNGL and Refined Products Transportation and ServicesCrude Oil Transportation and ServicesInvestment in Sunoco LPInvestment in USACAll OtherTotal
Balance, December 31, 2020$— $— $— $693 $52 $1,564 $— $82 $2,391 
Acquired— — — — 138 4 — — 142 
Balance, December 31, 2021— — — 693 190 1,568 — 82 2,533 
Acquired— — — — — 33 — — 33 
Balance, December 31, 2022$— $— $— $693 $190 $1,601 $— $82 $2,566 
 Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total
Balance, December 31, 2015$10
 $912
 $718
 $772
 $912
 $2,104
 $5,428
Reduction due to contribution of legacy Sunoco, Inc. retail business—
 —
 —
 —
 —
 (1,289) (1,289)
Acquired—
 —
 177
 —
 251
 —
 428
Impaired—
 (638) (32) —
 —
 —
 (670)
Balance, December 31, 201610
 274
 863
 772
 1,163
 815
 3,897
Acquired—
 —
 8
 —
 4
 —
 12
Impaired—
 (262) —
 (79) —
 (452) (793)
Other—
 —
 (1) —
 —
 —
 (1)
Balance, December 31, 2017$10
 $12
 $870
 $693
 $1,167
 $363
 $3,115
During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. The Partnership performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized goodwill impairments of $483 million related to our Ark-La-Tex and South Texas operations within the midstream segment, $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations.
During the third quarter of 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $1.28 billion related to our crude operations, $132 million related to our Energy Transfer Canada operations within the all other segment and $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline.
During the fourth quarter of 2020, the Partnership performed annual impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized goodwill impairments of $10 million related to our intrastate operations, $11 million related to our PEI operations and $15 million related to our Natural Resources operations within the all other segment primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified.
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments2021, $138 million of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.recorded in conjunction with the acquisition of Enable. In addition, Sunoco LP recorded $4 million of goodwill in conjunction with its acquisition of eight refined product terminals in 2021 and $33 million of goodwill in conjunction with its acquisitions in 2022.
During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.
During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determineddetermines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determineddetermines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determineddetermines the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimatedestimates a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair
F - 16
value estimates used in the long-lived asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.
Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $2.57 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2022, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted

risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligationARO in the periods in which management can reasonably estimate the settlement dates.
As of December 31, 2022 and 2021, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $362 million and $369 million, respectively. For the years ended December 31, 2022, 2021 and 2020 aggregate accretion expense related to AROs was $4 million, $12 million and $16 million, respectively.
Except for certain amountsthe AROs discussed below,above, management was not able to reasonably measure the fair value of asset retirement obligationsAROs as of December 31, 20172022 and 2016,2021, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s systemour systems are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. hasOur subsidiaries also have legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. isour subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligationsAROs related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligationsAROs will be settled. Consequently, these retirement obligationsAROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks.
As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet asAs of December 31, 20172022 and 2016, respectively. In addition,2021, other non-current assets on the Partnership had $21Partnership’s consolidated balance sheets included $27 million and $13$39 million, respectively, of funds that were legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets asAROs.
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Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
 December 31,
 20222021
Interest payable$559 $561 
Customer advances and deposits222 188 
Accrued capital expenditures565 461 
Accrued wages and benefits376 297 
Taxes payable other than income taxes519 384 
Exchanges payable224 155 
Deferred revenue268 158 
Other596 867 
Total accrued and other current liabilities$3,329 $3,071 
 December 31,
 2017 2016
Interest payable$443
 $440
Customer advances and deposits59
 56
Accrued capital expenditures1,006
 749
Accrued wages and benefits208
 212
Taxes payable other than income taxes108
 63
Exchanges payable154
 208
Other165
 177
Total accrued and other current liabilities$2,143
 $1,905
Deposits orIn certain circumstances, customer advances and deposits are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests
TheOur redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries hasthat have the option to sell itstheir interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interestnoncontrolling interests on ETP’sour consolidated balance sheet.sheets. See Note 7 for further information.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives and interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR or SOFR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2017,2022, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 20172022 and 20162021 based on inputs used to derive their fair values:
Fair Value TotalFair Value Measurements at December 31, 2022
Level 1Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX$60 $60 $— 
Swing Swaps IFERC75 75 — 
Fixed Swaps/Futures113 113 — 
Forward Physical Contracts10 — 10 
Power:
Forwards52 — 52 
Futures3 3 — 
NGLs – Forwards/Swaps317 317 — 
Refined Products – Futures20 20 — 
Crude – Forwards/Swaps38 38 — 
Total commodity derivatives688 626 62 
Other non-current assets27 18 9 
Total assets$715 $644 $71 
Liabilities:
Interest rate derivatives$(23)$— $(23)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX(25)(25)— 
Swing Swaps IFERC(12)(12)— 
Fixed Swaps/Futures(4)(4)— 
Forward Physical Contracts(2)— (2)
Power:
Forwards(51)— (51)
Futures(3)(3)— 
NGLs – Forwards/Swaps(358)(358)— 
Refined Products – Futures(59)(59)— 
Crude – Forwards/Swaps(12)(12)— 
Total commodity derivatives(526)(473)(53)
Total liabilities$(549)$(473)$(76)
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Fair Value Total Fair Value Measurements at December 31, 2017Fair Value TotalFair Value Measurements at December 31, 2021
Level 1 Level 2Level 1Level 2
Assets:     Assets:
Commodity derivatives:     Commodity derivatives:
Natural Gas:     Natural Gas:
Basis Swaps IFERC/NYMEX$11
 $11
 $—
Basis Swaps IFERC/NYMEX$7 $7 $— 
Swing Swaps IFERC13
 —
 13
Swing Swaps IFERC38 38 — 
Fixed Swaps/Futures70
 70
 —
Fixed Swaps/Futures26 26 — 
Forward Physical Swaps8
 —
 8
Forward Physical ContractsForward Physical Contracts7 — 7 
Power:     Power:
Forwards23
 —
 23
Forwards17 — 17 
Natural Gas Liquids – Forwards/Swaps193
 193
 —
Crude – Futures2
 2
 —
FuturesFutures6 6 — 
NGLs – Forwards/SwapsNGLs – Forwards/Swaps152 152 — 
Refined Products – FuturesRefined Products – Futures3 3 — 
Crude - Forwards/SwapsCrude - Forwards/Swaps16 16 — 
Total commodity derivatives320
 276
 44
Total commodity derivatives272 248 24 
Other non-current assets21
 14
 7
Other non-current assets39 26 13 
Total assets$341
 $290
 $51
Total assets$311 $274 $37 
Liabilities:     Liabilities:
Interest rate derivatives$(219) $—
 $(219)Interest rate derivatives$(387)$— $(387)
Commodity derivatives:     Commodity derivatives:
Natural Gas:     Natural Gas:
Basis Swaps IFERC/NYMEX(24) (24) —
Basis Swaps IFERC/NYMEX(10)(10)
Swing Swaps IFERC(15) (1) (14)Swing Swaps IFERC(6)(6)— 
Fixed Swaps/Futures(57) (57) —
Fixed Swaps/Futures(9)(9)— 
Forward Physical Swaps(2) —
 (2)
Power – Forwards(22) —
 (22)
Natural Gas Liquids – Forwards/Swaps(192) (192) —
Forward Physical ContractsForward Physical Contracts(6)— (6)
Power:Power:
ForwardsForwards(15)(15)
FuturesFutures(4)(4)— 
NGLs – Forwards/SwapsNGLs – Forwards/Swaps(140)(140)— 
Refined Products – Futures(25) (25) —
Refined Products – Futures(18)(18)— 
Crude – Futures(1) (1) —
Crude - Forwards/SwapsCrude - Forwards/Swaps(3)(3)— 
Total commodity derivatives(338) (300) (38)Total commodity derivatives(211)(190)(21)
Total liabilities$(557) $(300) $(257)Total liabilities$(598)$(190)$(408)

 Fair Value Total Fair Value Measurements at December 31, 2016
 Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $—
 $—
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Swaps1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options – Calls1
 1
 —
 —
Natural Gas Liquids – Forwards/Swaps233
 233
 —
 —
Refined Products – Futures1
 1
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives362
 355
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$375
 $363
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the Legacy ETP Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids – Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(17) (17) —
 —
Crude – Futures(13) (13) —
 —
Total commodity derivatives(472) (464) (8) —
Total liabilities$(666) $(464) $(201) $(1)
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2022 was $45.42 billion and $48.26 billion, respectively. As of December 31, 2021, the aggregate fair value and carrying amount of our debt obligations was $54.97 billion and $49.70 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
Contributions in Aid of Construction Costs
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.received.
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Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses
Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership and administrative personnel.
We record the collection of taxes to be remitted to government authorities on a net basis, except for our all other segment in which consumer excise taxes collected by Sunoco LP on sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss).income. For the yearyears ended December 31, 2015,2022, 2021 and 2020, excise taxes collected by Sunoco LP were $1.85 billion. The Partnership deconsolidated Sunoco LP effective July 1, 2015$285 million, $332 million and no excise taxes were collected by our consolidated operations subsequent to that date.$301 million, respectively.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest isinterests are adjusted as a change in partners’ capital.
Related Party Transactions
The Partnership regularly enters into related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. While the Partnership believes that such related party transactions generally reflect market rates, the pricing under such agreements may not be comparable to similar transactions with unaffiliated third parties. For the years ended December 31, 2022, 2021 and 2020, the Partnership’s consolidated income statements reflect revenues from related parties of $391 million, $410 million and $466 million, respectively.
Income Taxes
ETPEnergy Transfer is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, differences betweenin addition to the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).Agreement. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests.
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETPEnergy Transfer would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016,2022, 2021 and 2015,2020, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local, and foreign income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline CompanySunoco Retail LLC, and until July 31, 2015, Susser Holding Corporation.Aloha, among others. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
F - 21
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-BasedEquity Incentive Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Unitsthe underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Unitsthe underlying common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
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Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions
3.ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
Woodford Express Acquisition
On September 13, 2022, Energy Transfer completed the acquisition of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder100% of the IDRs pursuant to our Partnership Agreement,membership interests in Woodford Express, LLC, which owns a mid-continent gas gathering and processing system, for approximately $485 million plus working capital. The system, which is located in the heart of the SCOOP play, has 450 MMcf/d of cryogenic gas processing and treating capacity and over 200 miles of gathering lines, which are declaredconnected to Energy Transfer’s pipeline network. Woodford Express, LLC repaid aggregate principal of $292 million on its revolving credit facility and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners basedterm loan on their respective ownership interests.


3.ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
2018 Transactions
CDM Contribution Agreement
In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transactionacquisition, which amount is expected to closeincluded in the first halftotal consideration.
Energy Transfer Canada Sale
In August 2022, the Partnership completed the sale of 2018, subjectits 51% interest in Energy Transfer Canada. The sale resulted in cash proceeds to customary closing conditions.Energy Transfer of $302 million.
In connection withEnergy Transfer Canada’s assets and operations were included in the CDM Contribution Agreement, ETP entered into aPartnership’s all other segment until August 2022. Energy Transfer Canada did not meet the criteria to be reflected as discontinued operations in the Partnership’s consolidated statement of operations. Based on the anticipated proceeds upon signing of the share purchase agreement with ETE,in February 2022, during the three months ended March 31, 2022, the Partnership recorded a write-down on Energy Transfer Partners, L.L.C. (together with ETE,Canada’s assets of $300 million, of which $164 million was allocated to noncontrolling interests and $136 million was reflected in net income attributable to partners. Upon the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) allcompletion of the outstanding limited liability companysale in August 2022, the Partnership recorded an $85 million loss on deconsolidation.
Spindletop Assets Purchase
In March 2022, the Partnership purchased the membership interests in USA Compression GP,Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for approximately $325 million.
Sunoco LP’s Acquisitions
On November 30, 2022, Sunoco LP completed the general partneracquisition of USAC (“USAC GP”)Peerless Oil & Chemicals, Inc., an established terminal operator that distributes fuel products to over 100 locations within Puerto Rico and (ii) 12,466,912 USAC Common Unitsthroughout the Caribbean, for $76 million, net of cash consideration equalacquired.
On April 1, 2022, Sunoco LP completed the acquisition of a transmix processing and terminal facility in Huntington, Indiana for $252 million, net of cash acquired, of which $98 million was allocated to $250 million.intangible assets, $20 million to goodwill, $73 million to property, plant and equipment and $76 million to working capital.
2017 TransactionsEnable Acquisition
Rover Contribution Agreement
In October 2017, ETPOn December 2, 2021, the Partnership completed the previously announced contribution transactionmerger with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest inEnable (the “Enable Acquisition”). Under the holding company that owns 65%terms of the Rover pipeline (“Rover Holdco”). Asmerger agreement, Enable’s common unitholders received 0.8595 of an Energy Transfer common unit in exchange for each Enable common unit. In addition, each outstanding Enable Series A preferred unit was exchanged for 0.0265 of an Energy Transfer Series G Preferred Unit. A total of 384,780 Series G Preferred Units were issued in connection with the Enable Acquisition. The total fair value of Energy Transfer common units and Series G Preferred Units issued was approximately $3.5 billion at the closing date. Energy Transfer also made a result, Rover Holdco is now owned 50.1% by ETP$10 million cash payment for Enable’s general partner and 49.9% by Blackstone. Upon closing, Blackstone contributed fundsassumed $3.18 billion aggregate principal amount of Enable senior notes. In addition, Enable’s $800 million term loan and $35 million revolving credit facility were repaid and terminated in December 2021, immediately subsequent to reimburse ETP for its pro rata sharethe close of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.Enable Acquisition.
ETP and Sunoco Logistics Merger
As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger.
Permian Express Partners
In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
2016 Transactions
PennTexEnable Acquisition
On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, the Partnership purchased PennTex’s remaining outstanding common units in June 2017.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the PennTex acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their estimated fair values ason the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the utilization of an independent valuation specialist, if
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applicable, and involves the use of significant estimates and assumptions. Acquired assets were valued based on a combination of the acquisition date.discounted cash flow, the guideline company and the reproduction and replacement methods.
The totalfollowing table summarizes the allocation of the purchase price was allocated as follows:
  At November 1, 2016
Total current assets $34
Property, plant and equipment 393
Goodwill(1)
 177
Intangible assets 446
  1,050
   
Total current liabilities 6
Long-term debt, less current maturities 164
Other non-current liabilities 17
Noncontrolling interest 236
  423
Total consideration 627
Cash received 21
Total consideration, net of cash received $606
(1)
None of the goodwill is expected to be deductible for tax purposes.
The fair values ofamong the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.assumed:
Sunoco Logistics’ Vitol Acquisition
At December 2, 2021
Total current assets$593 
Property, plant and equipment, net7,076 
Investments in unconsolidated affiliates40 
Other non-current assets39 
Intangible assets, net440 
Goodwill138 
Total assets8,326 
Total current liabilities488 
Long-term debt, less current maturities(1)
4,267 
Other non-current liabilities18 
Total liabilities4,773 
Noncontrolling interests34 
Total consideration3,519 
Cash received61 
Total consideration, net of cash received$3,458 
In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics(1)Long-term debt at December 2, 2021 includes Enable senior notes with an approximately 2aggregate principal amount of $3.18 billion in senior notes and a fair value of $3.43 billion. It also includes $800 million barrel crude oil terminaloutstanding on the Enable 2019 Term Loan Agreement and $35 million outstanding on the Enable Five-Year Revolving Credit Facility, both of which were repaid and terminated in Midland, Texas, a crude oil gathering and mainline pipeline system inDecember 2021, immediately subsequent to the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million.

Bakken Financing
In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completionclose of the project-level financingEnable Acquisition.
4.INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Description of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $2.50 billion was outstanding under this credit facility.
Bayou Bridge
In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system.
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million. The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.Investments
Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated:
 Year Ended December 31, 2015
Revenues$12,482
Cost of products sold11,174
Operating expenses798
Selling, general and administrative expenses106
2015 Transactions
Sunoco LP
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.
In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE provided ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. At December 31, 2017, the Partnership held 37.8 million Sunoco LP common units accounted for under the equity method. Subsequent to Sunoco LP’s

repurchase of a portion of its common units on February 7, 2018, as discussed in Note 4, our investment in Sunoco LP consists of 26.2 million units. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.significant unconsolidated investees.
Bakken Pipeline
In March 2015, ETE transferred 46.2 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.
In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.
Regency Merger
On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy ETP Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

4.ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Citrus
ETP owns CrossCountry, which in turnEnergy Transfer owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,360-mile5,362-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.
FEP
We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. The Partnership recorded an impairment of its investment

in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.
MEP
We ownEnergy Transfer owns a 50% interest in MEP, which owns the Midcontinent Express Pipeline, an approximately 500 miles of500-mile natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment.
White Cliffs
Energy Transfer owns a 51% interest in White Cliffs, which consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline. These pipelines transport crude and NGLs from Platteville, Colorado to Cushing, Oklahoma. The Partnership evaluatedrecorded an impairment of its investment in MEP for impairment asWhite Cliffs of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308$129 million during the year ended December 31, 2016.
HPC
We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. The Partnership evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, the Partnership recorded a $172 million impairment of its equity method investment in HPC primarily2020 due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.
Sunoco LP
Effective July 1, 2015, ETE acquired 100%as a result of the overall market demand decline.
F - 24
Explorer
Energy Transfer owns a 15% membership interestsinterest in Explorer, which consists of Sunoco GP, the general partner of Sunoco LP,a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP,Houston, Texas and its remainingextends to Chicago, Illinois. Our investment in Sunoco LP is accounted for under the equity method. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units, andExplorer is reflected in the all otherour NGL and refined products transportation and services segment.
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash considerationSummary of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common unitsBalances Related to repay amounts outstanding under its revolving credit facility.Unconsolidated Affiliates
The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 20172022 and 20162021 were as follows:
 December 31,
 2017 2016
Citrus$1,754
 $1,729
FEP121
 101
MEP242
 318
HPC28
 382
Sunoco LP1,095
 1,225
Others576
 525
Total$3,816
 $4,280

December 31,
20222021
Citrus$1,800 $1,792 
MEP360 378 
White Cliffs218 245 
Explorer69 71 
Other446 461 
Total$2,893 $2,947 
The following table presents equity in earnings (losses) of unconsolidated affiliates:
Years Ended December 31,
202220212020
Citrus$141 $157 $162 
MEP10 (17)(6)
White Cliffs(8)— 20 
Explorer25 24 17 
Other (1)
89 82 (74)
Total equity in earnings of unconsolidated affiliates$257 $246 $119 
 Years Ended December 31,
 2017 2016 2015
Citrus$144
 $102
 $97
FEP53
 51
 55
MEP38
 40
 45
HPC(1)
(168) 31
 32
Sunoco, LLC—
 —
 (10)
Sunoco LP(2)
12
 (211) 202
Other77
 46
 48
Total equity in earnings of unconsolidated affiliates156
 59
 469
(1)For the year ended December 31, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $208 million.
(1)
For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(2)
For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, HPCWhite Cliffs and Sunoco LPExplorer (on a 100% basis) for all periods presented:
December 31,
20222021
Current assets$311 $319 
Property, plant and equipment, net7,722 7,803 
Other assets86 88 
Total assets$8,119 $8,210 
Current liabilities$291 $547 
Non-current liabilities4,347 4,110 
Equity3,481 3,553 
Total liabilities and equity$8,119 $8,210 
F - 25
 December 31,
 2017 2016
Current assets$4,750
 $1,532
Property, plant and equipment, net9,893
 10,310
Other assets2,286
 5,980
Total assets$16,929
 $17,822
    
Current liabilities$2,075
 $1,918
Non-current liabilities9,375
 10,343
Equity5,479
 5,561
Total liabilities and equity$16,929
 $17,822
Years Ended December 31,Years Ended December 31,
2017 2016 2015202220212020
Revenue$13,081
 $11,150
 $13,815
Revenue$1,518 $1,393 $1,405 
Operating income636
 859
 1,052
Operating income704 684 732 
Net income (loss)294
 (22) 664
Net incomeNet income463 446 480 
In addition to the equity method investments described above, we have other equity method investments which are not significant to our consolidated financial statements.


5.NET INCOME PER COMMON UNIT:
5.NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
The following table provides aBasic net income per common unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per common unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from Energy Transfer’s limited partner unit ownership in Sunoco LP that would have resulted assuming the incremental units related to Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.
A reconciliation of the numeratornet income and denominator of theweighted average units used in computing basic and diluted income (loss) per unit.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjustedis as follows:
 Years Ended December 31,
 202220212020
Net income$5,868 $6,687 $140 
Less: Net income attributable to redeemable noncontrolling interests51 50 49 
Less: Net income attributable to noncontrolling interests1,061 1,167 739 
Net income (loss), net of noncontrolling interests4,756 5,470 (648)
Less: General Partner’s interest in income (loss)4 6 (1)
Less: Preferred Unitholders’ interest in income422 285 — 
Common Unitholders’ interest in net income (loss)$4,330 $5,179 $(647)
Basic Income (Loss) per Common Unit:
Weighted average common units3,086.8 2,734.4 2,695.6 
Basic income (loss) per common unit$1.40 $1.89 $(0.24)
Diluted Income (Loss) per Common Unit:
Common Unitholders’ interest in net income (loss)$4,330 $5,179 $(647)
Dilutive effect of equity-based compensation of subsidiaries and distributions to convertible units(2)(2)— 
Diluted income (loss) available to Common Unitholders$4,328 $5,177 $(647)
Weighted average common units3,086.8 2,734.4 2,695.6 
Dilutive effect of unvested unit awards10.2 5.1 — 
Weighted average common units, assuming dilutive effect of unvested unit awards3,097.0 2,739.5 2,695.6 
Diluted income (loss) per common unit$1.40 $1.89 $(0.24)
F - 26
6.DEBT OBLIGATIONS:
In connection with the Sunoco Logistics Merger.Rollup Mergers on April 1, 2021, as discussed in Note 1, Energy Transfer entered into various supplemental indentures and assumed all the obligations of ETO under the respective indentures and credit agreements.
In November 2022, Energy Transfer and Panhandle completed an internal reorganization which resulted in Energy Transfer assuming all of Panhandle’s notes and debentures.
 Years Ended December 31,
 2017 2016 2015
Net income$2,501
 $583
 $1,489
Less: Income attributable to noncontrolling interest420
 295
 134
Less: Loss attributable to predecessor—
 —
 (34)
Net income, net of noncontrolling interest2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)986
 (1,019) (27)
Additional earnings allocated from (to) General Partner9
 (10) (5)
Distributions on employee unit awards, net of allocation to General Partner(27) (19) (16)
Net income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Basic net income (loss) per Common Unit$0.94
 $(1.38) $(0.07)
      
Income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Loss attributable to Legacy ETP Preferred Units—
 —
 (6)
Diluted income (loss) available to Common Unitholders$968
 $(1,048) $(54)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Dilutive effect of unvested Unit Awards5.1
 —
 —
Dilutive effect of Legacy ETP Preferred Units—
 —
 1.0
Weighted average Common Units – diluted1,037.8
 758.2
 650.2
Diluted income (loss) per Common Unit$0.93
 $(1.38) $(0.08)

6.DEBT OBLIGATIONS:
Our debt obligations consist of the following:
December 31,
20222021
Energy Transfer Indebtedness
4.65% Senior Notes due February 15, 2022(1)
$— $300 
5.00% Senior Notes due October 1, 2022(1)
— 700 
3.45% Senior Notes due January 15, 2023(2)(3)
350 350 
3.60% Senior Notes due February 1, 2023(2)(3)
800 800 
4.25% Senior Notes due March 15, 2023(3)
5 5 
4.25% Senior Notes due March 15, 2023(3)
995 995 
4.20% Senior Notes due September 15, 2023(3)
500 500 
4.50% Senior Notes due November 1, 2023(3)
600 600 
5.875% Senior Notes due January 15, 202423 23 
7.60% Senior Notes due February 1, 2024(4)
82 — 
5.875% Senior Notes due January 15, 20241,127 1,127 
4.90% Senior Notes due February 1, 2024350 350 
7.60% Senior Notes due February 1, 2024277 277 
4.25% Senior Notes due April 1, 2024500 500 
4.50% Senior Notes due April 15, 2024750 750 
3.90% Senior Notes due May 15, 2024600 600 
9.00% Debentures due November 1, 202465 65 
4.05% Senior Notes due March 15, 20251,000 1,000 
2.90% Senior Notes due May 15, 20251,000 1,000 
5.95% Senior Notes due December 1, 2025400 400 
4.75% Senior Notes due January 15, 20261,000 1,000 
3.90% Senior Notes due July 15, 2026550 550 
4.40% Senior Notes due March 15, 2027700 700 
4.20% Senior Notes due April 15, 2027600 600 
5.50% Senior Notes due June 1, 202744 44 
5.50% Senior Notes due June 1, 2027956 956 
4.00% Senior Notes due October 1, 2027750 750 
5.55% Senior Notes due February 15, 20281,000 — 
4.95% Senior Notes due May 15, 2028800 800 
4.95% Senior Notes due June 15, 20281,000 1,000 
5.25% Senior Notes due April 15, 20291,500 1,500 
7.00% Senior Notes due July 15, 2029(4)
66 — 
4.15% Senior Notes due September 15, 2029547 547 
8.25% Senior Notes due November 15, 2029(4)
33 — 
8.25% Senior Notes due November 15, 2029267 267 
3.75% Senior Note due May 15, 20301,500 1,500 
5.75% Senior Notes due February 15, 20331,500 — 
4.90% Senior Notes due March 15, 2035500 500 
6.625% Senior Notes due October 15, 2036400 400 
F - 27
 December 31,
 2017 2016
ETP Debt   
6.125% Senior Notes due February 15, 2017$—
 $400
2.50% Senior Notes due June 15, 2018 (1)650
 650
6.70% Senior Notes due July 1, 2018 (1)600
 600
9.70% Senior Notes due March 15, 2019400
 400
9.00% Senior Notes due April 15, 2019450
 450
5.50% Senior Notes due February 15, 2020250
 250
5.75% Senior Notes due September 1, 2020400
 400

5.80% Senior Notes due June 15, 2038500 500 
7.50% Senior Notes due July 1, 2038550 550 
6.85% Senior Notes due February 15, 2040250 250 
6.05% Senior Notes due June 1, 2041700 700 
6.50% Senior Notes due February 1, 20421,000 1,000 
6.10% Senior Notes due February 15, 2042300 300 
4.95% Senior Notes due January 15, 2043350 350 
5.15% Senior Notes due February 1, 2043450 450 
5.95% Senior Notes due October 1, 2043450 450 
5.30% Senior Notes due April 1, 2044700 700 
5.00% Senior Notes due May 15, 2044531 531 
5.15% Senior Notes due March 15, 20451,000 1,000 
5.35% Senior Notes due May 15, 2045800 800 
6.125% Senior Notes due December 15, 20451,000 1,000 
5.30% Senior Notes due April 15, 2047900 900 
5.40% Senior Notes due October 1, 20471,500 1,500 
6.00% Senior Notes due June 15, 20481,000 1,000 
6.25% Senior Notes due April 15, 20491,750 1,750 
5.00% Senior Notes due May 15, 20502,000 2,000 
Floating Rate Junior Subordinated Notes due November 1, 2066600 546 
Five-Year Credit Facility793 2,937 
Unamortized premiums, discounts and fair value adjustments, net184 233 
Deferred debt issuance costs(181)(186)
40,264 40,717 
Subsidiary Indebtedness
Transwestern Debt
5.89% Senior Notes due May 24, 2022(1)
— 150 
5.66% Senior Notes due December 9, 2024175 175 
6.16% Senior Notes due May 24, 203775 75 
250 400 
Panhandle Debt
7.60% Senior Notes due February 1, 2024(4)
— 82 
7.00% Senior Notes due July 15, 2029(4)
— 66 
8.25% Senior Notes due November 15, 2029(4)
— 33 
Floating Rate Junior Subordinated Notes due November 1, 2066(4)
— 54 
Unamortized premiums, discounts and fair value adjustments, net(4)
— 8 
— 243 
Bakken Project Debt
3.625% Senior Notes due April 1, 2022(1)
— 650 
3.90% Senior Notes due April 1, 20241,000 1,000 
4.625% Senior Notes due April 1, 2029850 850 
F - 28
4.15% Senior Notes due October 1, 20201,050
 1,050
4.40% Senior Notes due April 1, 2021600
 600
6.50% Senior Notes due July 15, 2021—
 500
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
4.65% Senior Notes due February 15, 2022300
 300
5.875% Senior Notes due March 1, 2022900
 900
5.00% Senior Notes due October 1, 2022700
 700
3.45% Senior Notes due January 15, 2023350
 350
3.60% Senior Notes due February 1, 2023800
 800
5.50% Senior Notes due April 15, 2023—
 700
4.50% Senior Notes due November 1, 2023600
 600
4.90% Senior Notes due February 1, 2024350
 350
7.60% Senior Notes due February 1, 2024277
 277
4.25% Senior Notes due April 1, 2024500
 500
9.00% Debentures due November 1, 202465
 65
4.05% Senior Notes due March 15, 20251,000
 1,000
5.95% Senior Notes due December 1, 2025400
 400
4.75% Senior Notes due January 15, 20261,000
 1,000
3.90% Senior Notes due July 15, 2026550
 550
4.20% Senior Notes due April 15, 2027600
 —
4.00% Senior Notes due October 1, 2027750
 —
8.25% Senior Notes due November 15, 2029267
 267
4.90% Senior Notes due March 15, 2035500
 500
6.625% Senior Notes due October 15, 2036400
 400
7.50% Senior Notes due July 1, 2038550
 550
6.85% Senior Notes due February 15, 2040250
 250
6.05% Senior Notes due June 1, 2041700
 700
6.50% Senior Notes due February 1, 20421,000
 1,000
6.10% Senior Notes due February 15, 2042300
 300
4.95% Senior Notes due January 15, 2043350
 350
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
5.30% Senior Notes due April 1, 2044700
 700
5.15% Senior Notes due March 15, 20451,000
 1,000
5.35% Senior Notes due May 15, 2045800
 800
6.125% Senior Notes due December 15, 20451,000
 1,000
5.30% Senior Notes due April 15, 2047900
 —
5.40% Senior Notes due October 1, 20471,500
 —
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Unamortized premiums, discounts and fair value adjustments, net33
 66
Deferred debt issuance costs(170) (166)
 29,210
 29,454
Transwestern Debt   
5.64% Senior Notes due May 24, 2017—
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Deferred debt issuance costs(1) (1)
 574
 656
Panhandle Debt   
6.20% Senior Notes due November 1, 2017—
 300
Unamortized premiums, discounts and fair value adjustments, net(1)(2)
Deferred debt issuance costs(7)(9)
1,842 2,489 
Sunoco LP Debt
6.00% Senior Notes Due April 15, 2027600 600 
5.875% Senior Notes Due March 15, 2028400 400 
4.50% Senior Notes due May 15, 2029800 800 
4.50% Senior Notes due April 30, 2030800 800 
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023900 581 
Lease-related obligations94 100 
Deferred debt issuance costs(23)(26)
3,571 3,255 
USAC Debt
6.875% Senior Notes due April 1, 2026725 725 
6.875% Senior Notes due September 1, 2027750 750 
USAC $1.60 billion Revolving Credit Facility due December 2026(5)
646 516 
Deferred debt issuance costs(14)(18)
2,107 1,973 
HFOTCO Debt
HFOTCO Tax Exempt Notes due 2050225 225 
Unamortized premiums, discounts and fair value adjustments, net— (1)
225 224 
Energy Transfer Canada Debt
Energy Transfer Canada facilities(6)
— 398 
— 398 
Other3 3 
Total debt48,262 49,702 
Less: Current maturities of long-term debt2 680 
Long-term debt, less current maturities$48,260 $49,022 

(1)These notes were redeemed in 2022.
(2)These notes were redeemed in the first quarter of 2023.
(3)As of December 31, 2022, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis.
(4)As discussed previously, Panhandle’s debt was assumed by Energy Transfer during 2022 as a result of an internal reorganization.
(5)The USAC Credit Facility matures in December 2026, except that if any portion of the 6.875% Senior Notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025.
(6)These facilities were included in the August 2022 Energy Transfer Canada divestiture as discussed in Note 3.
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7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 15, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net28
 50
 813
 1,135
Sunoco, Inc. Debt   
5.75% Senior Notes due January 15, 2017—
 400
    
Bakken Project Debt   
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
Deferred debt issuance costs(8) (13)
 2,492
 1,087
PennTex Debt   
PennTex $275 million Revolving Credit Facility due December 2019—
 168
    
Other5
 30
 33,094
 32,930
Less: Current maturities of long-term debt407
 1,189
 $32,687
 $31,741
(1)
As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
(2)
Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $118$42 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs:costs, net:
2018 $1,700
2019 3,500
2020 1,875
2021 1,400
2022 5,346
Thereafter 19,391
Total $33,212
2023$3,250 
20245,175 
20252,400 
20262,921 
20276,093 
Thereafter28,465 
Total$48,304 
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
ETP Notes and Debentures
Senior Notes
The ETPEnergy Transfer Senior Notes are the Partnership’s senior notes were registeredobligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. Energy Transfer’s obligations under the Securities ActEnergy Transfer Senior Notes previously were secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the Energy Transfer Term Loan Facility, by a lien on substantially all of 1933 (as amended).Energy Transfer’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. Subsequent to the termination of the Revolver Credit Agreement and the Energy Transfer Term Loan Facility, the collateral securing the Energy Transfer Senior Notes was released. The Partnership may redeem someEnergy Transfer Senior Notes are not guaranteed by any of its subsidiaries.
The covenants related to the Energy Transfer Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligations of the Partnership and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.Partnership’s assets.
Credit Facilities and Commercial Paper
ETPFive-Year Credit FacilitiesFacility
On December 1, 2017 the Partnership entered into a five-year, $4.0The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETPApril 11, 2027. The Five-Year Credit Facilities”).  The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitmentscommitment may be increased up to $6.0$7.00 billion under certain conditions. We use the ETP Credit Facilities to provide temporary financing for our growth projects, as well as for general partnership purposes.
As of December 31, 2017,2022, the ETP Five-Year Credit Facility had $2.29 billion$793 million of outstanding borrowings, of which $2.01 billion was$750 million consisted of commercial paper. The amount available for future borrowings was $1.56$4.18 billion, after taking into accountaccounting for outstanding letters of credit in the amount of $150$32 million. The weighted average interest rate on the total amount outstanding as of December 31, 20172022 was 2.48%5.12%.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2017,2022, the ETP 364-DaySunoco LP Credit Facility had $50$900 million of outstanding borrowings and the$7 million in standby letters of credit and matures in July 2023. The amount available for future borrowings was $950 million.$593 million at December 31, 2022. The weighted average interest rate on the total amount outstanding as of December 31, 20172022 was 5.00%6.17%.
ETLPUSAC Credit Facility
The ETLPUSAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”) which matures on December 8, 2026, except that if any portion of USAC’s senior notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility allowed for borrowings ofwill mature on December 31, 2025. The USAC Credit Facility also permits up to $3.75 billion and was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment$200 million of the ETP Credit Facilities on December 1, 2017.
Sunoco Logistics Credit Facilities
ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger orfuture increases in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”).borrowing capacity. As of December 31, 2017, the Bakken Credit Facility2022, USAC had $2.50 billion$646 million of outstanding borrowings. borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2022, USAC had $954 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $333 million.
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The weighted average interest rate on the total amount outstanding as of December 31, 20172022 was 3.00%6.84%.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

Covenants Related to Our Credit Agreements
Covenants Related to ETP
The agreements relating to the ETP senior notesSenior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The ETPFive-Year Credit FacilitiesFacility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
•incur indebtedness;
•grant liens;
•enter into mergers;
•dispose of assets;
•make certain investments;
•make Distributions (as defined in the ETPFive-Year Credit Facilities)Facility) during certain Defaults (as defined in the ETPFive-Year Credit Facilities)Facility) and during any Event of Default (as defined in the ETPFive-Year Credit Facilities)Facility);
•engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
•engage in transactions with affiliates; and
•enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Credit Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Credit Facility ranges from 0.125% to 0.300%. 
The applicable margin for eurodollar rate loans under the ETP 364-DayFive-Year Credit Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The ETP Credit Facilities containcontains various covenants including limitations on the creation of indebtedness and liens and related to the operation and conduct of our business. The ETPFive-Year Credit FacilitiesFacility also limitlimits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements,agreement, of 5.05.00 to 1,1.00, which can generally be increased to 5.55.50 to 11.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.963.32 to 11.00 at December 31, 2017,2022, as calculated in accordance with the credit agreements.agreement.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.
Covenants Related to Transwestern
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-

acceleration and prepayment of debt provisions.assets. A breach of any of these covenants could result in acceleration of Panhandle’s debtdebt.
F - 31
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other financial obligationsthings:
•grant liens;
•make certain loans or investments;
•incur additional indebtedness or guarantee other indebtedness;
•enter into transactions with affiliates;
•merge or consolidate;
•sell our assets; and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are•make certain acquisitions.
The USAC Credit Facility is also subject to certain additional restrictionsthe following financial covenants, including covenants requiring USAC to maintain:
•a minimum EBITDA to interest coverage ratio;
•a ratio of total secured indebtedness to EBITDA within a specified range; and
•a maximum funded debt to EBITDA ratio.
Covenants Related to the HFOTCO Tax Exempt Notes
The indentures covering HFOTCO’s tax exempt notes due 2050 (“IKE Bonds”) include customary representations and warranties and affirmative and negative covenants. These restrictions andSuch covenants include limitations on additional debt at somethe creation of its subsidiaries; limitations on the usenew liens, indebtedness, making of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds.
Compliance with our Covenants
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.2022.

7.LEGACY ETP PREFERRED UNITS:
The Legacy ETP7.REDEEMABLE NONCONTROLLING INTERESTS:
Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of December 31, 2022 included a balance of $477 million related to the USAC Preferred Units, were mandatorily redeemable on September 2, 2029 for $35described below, and a balance of $16 million plus all accrued but unpaid distributions andrelated to noncontrolling interest thereon and were reflected as long-term liabilitiesholders in our consolidated balance sheets. The Legacy ETP Preferred Units were entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record datesone of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. As of December 31, 2021, redeemable noncontrolling interests included a balance of $477 million related to the USAC Preferred Units, a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership and a balance of $291 million related
F - 32
to Energy Transfer Canada preferred shares. The Energy Transfer Canada preferred shares were deconsolidated in connection with the sale in August 2022.
USAC Series A Preferred Units
As of December 31, 2022, USAC had 500,000 preferred units issued and outstanding. The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units are convertible into USAC common unitunits at the election of the holders. As of December 31, 2022, a total of 333,333 USAC Preferred Units are convertible, at the option of the holder, into a maximum of 16,657,088 USAC common units, including unpaid cash distributions. In January 2017, ETP repurchasedAs of April 2, 2023, all of its 1.9 million outstanding Legacy ETPthe USAC Preferred Units will be convertible, at the option of the holder, into a maximum of 24,985,633 USAC common units. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by the fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cashcash. In addition, beginning April 2028, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and USAC may elect to pay up to 50% of such redemption amount in USAC common units.
8.EQUITY:
Limited Partner Units
Limited partner interests in the aggregate amount of $53 million.

8.EQUITY:
Limited Partner interestsPartnership are represented by Common Class E Units, Class G Units, Class I Units, Class J Units and Class K Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s outstanding securities also include preferred units, as described below. No personCommon Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP hasone vote per unit on all matters presented to the right, in connection withLimited Partners for a vote. In addition, if at any time any person or group (other than the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GPPartnership’s General Partner and its affiliatesaffiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to maintainbe outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately priorpresence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to such issuance.

IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please readas described at “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiaryCash.”
Our Partnership Agreement contains specific provisions for the allocation of ETE, ownsnet earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner (which currently holds an approximately 0.1% general partner interest) until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the IDRs.Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
Common Units
The change in Energy Transfer Common Units during the years ended December 31, 2022, 2021 and 2020 was as follows:
 Years Ended December 31,
 202220212020
Number of Common Units, beginning of period3,082.5 2,702.4 2,689.6 
Common Units issued in mergers and acquisitions (1)
— 374.6 — 
Common Units repurchased— (4.2)— 
Issuance of Common Units (2)
11.9 9.7 12.8 
Number of Common Units, end of period3,094.4 3,082.5 2,702.4 
 Years Ended December 31,
 
2017 (1)
 
2016 (1)
 
2015 (1)
Number of Common Units, beginning of period794.8
 758.5
 533.4
Common Units redeemed in connection with certain transactions—
 (26.7) (77.8)
Common Units issued in connection with public offerings54.0
 —
 —
Common Units issued in connection with certain acquisitions—
 13.3
 258.2
Common Units issued in connection with the Distribution Reinvestment Plan12.0
 9.9
 11.7
Common Units issued in connection with Equity Distribution Agreements22.6
 39.0
 31.7
Common Units issued to ETE in a private placement transaction23.7
 —
 —
Common Unit increase from Sunoco Logistics Merger (2)255.4
 —
 —
Issuance of Common Units under equity incentive plans1.6
 0.8
 1.3
Number of Common Units, end of period1,164.1
 794.8
 758.5
(1)
The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
(2)
Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.
Our(1)In December 2021, Energy Transfer issued 374.6 million Energy Transfer Common Units are registered underin connection with the Securities Exchange ActEnable Acquisition.
(2)Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
F - 33
Energy Transfer Class A Units
As of February 10, 2023, the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presentedPartnership had outstanding 765,933,429 Class A units (“Energy Transfer Class A Units”) representing limited partner interests in the Partnership to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement.Partner. The CommonEnergy Transfer Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, Energy Transfer’s Partnership Agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of Energy Transfer Class A Units additional Energy Transfer Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The Energy Transfer Class A Units are not entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”and otherwise have no economic attributes.
Equity DistributionEnergy Transfer Repurchase Program
From timeIn February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to time, we have sold$2 billion of Energy Transfer Common Units through equity distribution agreements. Such sales ofin the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership did not repurchase any Energy Transfer Common Units are made by meansunder this program in 2022 and repurchased 4.2 million in 2021. As of ordinary brokers’ transactions onDecember 31, 2022, $880 million remained available to repurchase under the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements.current program.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.Distribution Reinvestment Program
During the year ended December 31, 2017, we issued 22.62022, distributions of $61 million units for $503 million, net of commissions of $5 million.were reinvested under the distribution reinvestment program. As of December 31, 2017, $752 million of our Common Units remained available to be issued under our currently effective equity distribution agreement.
Equity Incentive Plan Activity
We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.

Distribution Reinvestment Program
Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan.
During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.
As of December 31, 2017,2022, a total of 20.812 million Common Unitscommon units remain available to be issued under the existing registration statement.
August 2017 Units Offering
In August 2017, the Partnership issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
January 2017 Private Placement
In January 2017, the Partnership sold 23.7 million ETP Common Units to ETE in a private placement transaction for gross proceeds of approximately $568 million.
Class E Units
There are currently 8.9 million Class E Units outstanding, all of which are currently owned by HHI. The Class E Units generally do not have any voting rights. The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the Class E Units at a future date.
Class G Units
There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year. Allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements.
Class H Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelledstatement in connection with the merger of ETP and Sunoco Logistics in April 2017.distribution reinvestment program.
Class IEnergy Transfer Preferred Units
In connection with the Bakken Pipeline Transaction discussed in Note 3, in April 2015, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the

cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Class K Units
On December 29, 2016, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco.  If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP.
Sales of Common Units by legacy Sunoco Logistics
Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of2022, Energy Transfer’s outstanding preferred units by the respective subsidiary (excluding transactions with us) as capital transactions.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.
ETP Preferred Units
In November 2017, ETP issuedincluded 950,000 of its 6.250% Series A Preferred Units, at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units, at a price of $1,000 per unit.18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units and 900,000 Series H Preferred Units.
The following table summarizes changes in the Energy Transfer Preferred Units:
Preferred Unitholders
Series ASeries BSeries CSeries DSeries ESeries FSeries GSeries HTotal
Balance, December 31, 2020$— $— $— $— $— $— $— $— $— 
Preferred units conversion943 547 440 434 786 504 1,114 — 4,768 
Units issued for cash— — — — — — — 889 889 
Distributions to partners(30)(18)(25)(25)(45)(34)(79)(24)(280)
Units issued in Enable Acquisition— — — — — — 392 — 392 
Other, net— — — — — — — (3)(3)
Net income45 27 25 25 45 26 61 31 285 
Balance, December 31, 2021958 556 440 434 786 496 1,488 893 6,051 
Distributions to partners(59)(36)(33)(34)(61)(34)(106)(59)(422)
Net income59 36 33 34 61 34 106 59 422 
Balance, December 31, 2022$958 $556 $440 $434 $786 $496 $1,488 $893 $6,051 
Energy Transfer Series A Preferred Units
Distributions on the Energy Transfer Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Energy Transfer Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.028% per annum. The Energy Transfer Series A Preferred Units are redeemable at ETP’sEnergy Transfer’s option on or after February 15, 2023 at a redemption price of $1,000 per Energy Transfer Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
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Energy Transfer Series B Preferred Units
Distributions on the Energy Transfer Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Energy Transfer Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation

preference equal to an annual floating rate of the three-month LIBOR, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.155% per annum. The Energy Transfer Series B Preferred Units are redeemable at ETP’sEnergy Transfer’s option on or after February 15, 2028 at a redemption price of$1,000of $1,000 per Energy Transfer Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
PennTex Tender OfferEnergy Transfer Series C Preferred Units
Distributions on the Energy Transfer Series C Preferred Units will accrue and Limited Call Right Exercisebe cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Energy Transfer Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.530% per annum. The Energy Transfer Series C Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2023 at a redemption price of $25 per Energy Transfer Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Energy Transfer Series D Preferred Units
Distributions on the Energy Transfer Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Energy Transfer Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.738% per annum. The Energy Transfer Series D Preferred Units are redeemable at Energy Transfer’s option on or after August 15, 2023 at a redemption price of $25 per Energy Transfer Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Energy Transfer Series E Preferred Units
Distributions on the Energy Transfer Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the Energy Transfer Series E Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a successor rate, in each case determined quarterly by our calculation agent, plus a spread of 5.161% per annum. The Energy Transfer Series E Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2024 at a redemption price of $25 per Energy Transfer Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Energy Transfer Series F Preferred Units
Distributions on the Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the Energy Transfer Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The Energy Transfer Series F Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2025 at a redemption price of $1,000 per Energy Transfer Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Energy Transfer Series G Preferred Units
Distributions on the Energy Transfer Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Energy Transfer Series G Preferred Units will equal a percentage of the
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$1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The Energy Transfer Series G Preferred Units are redeemable at Energy Transfer’s option on or after May 15, 2030 at a redemption price of $1,000 per Energy Transfer Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. On December 2, 2021, Energy Transfer issued 384,780 Energy Transfer Series G Preferred Units in connection with the Enable Acquisition, as discussed in Note 3.
Energy Transfer Series H Preferred Units
On June 15, 2021, Energy Transfer issued 900,000 of its 6.500% Series H Preferred Units at a price to the public of $1,000 per unit. Distributions on the Series H Preferred Units will accrue and be cumulative to, but excluding, November 15, 2026, at a rate equal to 6.500% per annum of the $1,000 liquidation preference. On and after November 15, 2026 and each fifth anniversary thereafter, the distribution rate on the Series H Preferred Units will reset to be a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.694% per annum. Distributions on the Series H Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series H Preferred Units are redeemable at Energy Transfer’s option during the three-month period prior to, and including, each distribution reset date at a redemption price of $1,000 per Series H Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Sale of Common Units by Subsidiaries
Energy Transfer on a stand-alone basis (the “Parent Company”) accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.
Subsidiary Equity Transactions
USAC’s Distribution Reinvestment Program
During the years ended December 31, 2022, 2021 and 2020, USAC issued 124,255, 118,399 and 188,695 USAC common units, respectively, under the USAC distribution reinvestment program.
USAC’s Warrants
In June 2017, ETP purchased allApril 2022, USAC issued 534,308 of the outstanding PennTexits common units not previously owned by ETP for $20.00in connection with the exercise of outstanding warrants.
As of December 31, 2022, one tranche of USAC Warrants with the right to purchase 10,000,000 common units at a strike price of $19.59 per common unit in cash. ETP now ownswas outstanding and may be exercised by the holders at any time before April 2, 2028.
Energy Transfer Common Unit Distributions
Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of the economic interestsour available cash quarterly.
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Our distributions declared and PennTexpaid with respect to our common units were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2019February 7, 2020February 19, 2020$0.3050 
March 31, 2020May 7, 2020May 19, 20200.3050 
June 30, 2020August 7, 2020August 19, 20200.3050 
September 30, 2020November 6, 2020November 19, 20200.1525 
December 31, 2020February 8, 2021February 19, 20210.1525 
March 31, 2021May 11, 2021May 19, 20210.1525 
June 30, 2021August 6, 2021August 19, 20210.1525 
September 30, 2021November 5, 2021November 19, 20210.1525 
December 31, 2021February 8, 2022February 18, 20220.1750 
March 31, 2022May 9, 2022May 19, 20220.2000 
June 30, 2022August 8, 2022August 19, 20220.2300 
September 30, 2022November 4, 2022November 21, 20220.2650 
December 31, 2022February 7, 2023February 21, 20230.3050 
Energy Transfer Preferred Unit Distributions
Distributions on Energy Transfer’s Series A, Series B, Series C, Series D, Series E, Series F, Series G and Series H preferred units declared and/or paid by Energy Transfer were as follows:
Period EndedRecord DatePayment Date
Series A (1)
Series B (1)
Series CSeries DSeries E
Series F (1)
Series G (1)
Series H (1)
March 31, 2021May 3, 2021May 17, 2021$—$—$0.4609$0.4766$0.4750$33.7500$35.63$—
June 30, 2021August 2, 2021August 16, 202131.2533.130.46090.47660.4750———
September 30, 2021November 1, 2021November 15, 2021——0.46090.47660.475033.750035.6327.08*
December 31, 2021February 1, 2022February 15, 202231.2533.130.46090.47660.4750———
March 31, 2022May 2, 2022May 16, 2022——0.46090.47660.475033.750035.6332.50
June 30, 2022August 1, 2022August 15, 202231.2533.130.46090.47660.4750———
September 30, 2022November 1, 2022November 15, 2022——0.46090.47660.475033.750035.6332.50
December 31, 2022February 1, 2023February 15, 202331.2533.130.46090.47660.4750———
*    Represents prorated initial distribution.
(1)    Series A, Series B, Series F, Series G and Series H distributions are no longer publicly traded or listedcurrently paid on a semi-annual basis. Pursuant to their terms, distributions on the NASDAQ.Series A and Series B preferred units will be paid quarterly beginning after February 15, 2023 and February 15, 2028, respectively
QuarterlySunoco LP Cash Distributions
Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Available Cash
Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the holders of theSunoco LP’s incentive distribution rights receive increasing percentages, up to 48 percent,rights. As of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”December 31, 2022, Sunoco LP had approximately 84.1 million common units outstanding.
The following table showsillustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, and distribution “splits” betweenafter the general and limited partnerspayment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the holderscommon unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit
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    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
target amount.” The percentage interests shown for thecommon unitholders and the general partnerIDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target AmountCommon UnitholdersHolder of IDRs
Minimum Quarterly Distribution $0.4375100%—%
First Target Distribution$0.4375 to $0.503125100%—%
Second Target Distribution$0.503125 to $0.54687585%15%
Third Target Distribution$0.546875 to $0.65625075%25%
ThereafterAbove $0.65625050%50%
Distributions on commonSunoco LP’s units declared andand/or paid by ETP and Sunoco Logistics during the pre-merger periodsLP were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2019February 7, 2020February 19, 2020$0.8255 
March 31, 2020May 7, 2020May 19, 20200.8255 
June 30, 2020August 7, 2020August 19, 20200.8255 
September 30, 2020November 6, 2020November 19, 20200.8255 
December 31, 2020February 8, 2021February 19, 20210.8255 
March 31, 2021May 11, 2021May 19, 20210.8255 
June 30, 2021August 6, 2021August 19, 20210.8255 
September 30, 2021November 5, 2021November 19, 20210.8255 
December 31, 2021February 8, 2022February 18, 20220.8255 
March 31, 2022May 9, 2022May 19, 20220.8255 
June 30, 2022August 8, 2022August 19, 20220.8255 
September 30, 2022November 4, 2022November 18, 20220.8255 
December 31, 2022February 7, 2023February 21, 20230.8255 
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200
USAC Cash Distributions

Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2022, USAC had approximately 98.2 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.
Distributions on commonUSAC’s units declared andand/or paid by Post-Merger ETPUSAC were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2019January 27, 2020February 7, 2020$0.5250 
March 31, 2020April 27, 2020May 8, 20200.5250 
June 30, 2020July 31, 2020August 10, 20200.5250 
September 30, 2020October 26, 2020November 6, 20200.5250 
December 31, 2020January 25, 2021February 5, 20210.5250 
March 31, 2021April 26, 2021May 7, 20210.5250 
June 30, 2021July 26, 2021August 6, 20210.5250 
September 30, 2021October 25, 2021November 5, 20210.5250 
December 31, 2021January 24, 2022February 4, 20220.5250 
March 31, 2022April 25, 2022May 6, 20220.5250 
June 30, 2022July 25, 2022August 5, 20220.5250 
September 30, 2022October 24, 2022November 4, 20220.5250 
December 31, 2022January 23, 2023February 3, 20230.5250 
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Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared and paid by ETP to the preferred unitholders were as follows:
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
December 31, December 31,
2017 2016 20222021
Available-for-sale securities$8
 $2
Available-for-sale securities$9 $19 
Foreign currency translation adjustment(5) (5)Foreign currency translation adjustment1 13 
Actuarial gain related to pensions and other postretirement benefits(5) 7
Actuarial gain (loss) related to pensions and other postretirement benefitsActuarial gain (loss) related to pensions and other postretirement benefits(7)5 
Investments in unconsolidated affiliates, net5
 4
Investments in unconsolidated affiliates, net13 (11)
Total AOCI, net of tax$3
 $8
Total AOCI, net of tax16 26 
Amounts attributable to noncontrolling interestsAmounts attributable to noncontrolling interests— (3)
Total AOCI included in partners’ capital, net of taxTotal AOCI included in partners’ capital, net of tax$16 $23 
The following table below sets forth the tax amounts included in the respective components of other comprehensive income:
 December 31,
 20222021
Available-for-sale securities$1 $(1)
Foreign currency translation adjustment6 6 
Actuarial loss relating to pension and other postretirement benefits1 1 
Total$8 $6 
 December 31,
 2017 2016
Available-for-sale securities$(2) $(2)
Foreign currency translation adjustment3
 3
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$4
 $1

9.UNIT-BASED COMPENSATION PLANS:
ETP Unit-Based Compensation Plan9.EQUITY INCENTIVE PLANS:
We, Sunoco LP and USAC, have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent

rights (“DERs”), Common Unitcommon unit appreciation rights, cash restricted units and other unit-basedequity-based compensation awards. As of December 31, 2017,2022, an aggregate total of 8.43.6 million ETPEnergy Transfer Common Units remain available to be awarded under our equity incentive plans.
Restricted UnitsEnergy Transfer Long-Term Incentive Plan
We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETPEnergy Transfer Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement.
The following table shows the activity of the awards granted to employees and non-employee directors:
Number of UnitsWeighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2021Unvested awards as of December 31, 202136.1 $9.49 
Number of Units Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 20169.4
 $27.68
Legacy Sunoco Logistics unvested awards as of December 31, 20163.2
 28.57
Awards granted4.9
 17.69
Awards granted12.4 11.56 
Awards vested(2.3) 34.22
Awards vested(9.3)11.79 
Awards forfeited(1.1) 25.03
Awards forfeited(1.5)9.39 
Unvested awards as of December 31, 201714.1
 23.18
Unvested awards as of December 31, 2022Unvested awards as of December 31, 202237.7 $9.62 
During the years ended December 31, 2017, 2016,2022, 2021, and 2015,2020, the weighted average grant-date fair value per unit award granted was $17.69, $23.82$11.56, $8.46 and $23.47, respectively. The$6.29, respectively, and the total fair value of awards vested was $40$103 million, $40$52 million and $57$51 million, respectively, based on the market price of ETPthe respective Common Units as of the vesting date. As of December 31, 2017,2022, a total of 14.137.7 million unit awards remain unvested, for which ETPEnergy Transfer expects to recognize a total of $189$248 million in compensation expense over a weighted average period of 2.73.09 years.
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Cash Restricted Units. The Partnership previouslyhas also granted cash restricted units, which entitledvest through three years of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETPEnergy Transfer Common Unit upon vesting. TheFor the years ended December 31, 2022, 2021 and 2020, the Partnership does not currently have anygranted a total of 3.8 million, 3.9 million and 7.7 million cash restricted units, outstanding.respectively. As of December 31, 2022, a total of 8.5 million cash restricted units were unvested. As of December 31, 2022, the Partnership’s consolidated balance sheet reflected aggregate liabilities of $4.2 million related to cash restricted units.

Subsidiary Long-Term Incentive Plans
10.INCOME TAXES:
Each of Sunoco LP and USAC has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards”) to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a three or five-year period, that entitles the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.
The following table summarizes the activity of the Subsidiary Unit Awards:
Sunoco LPUSAC
Number of
Units		Weighted  Average
Grant-Date Fair Value
Per Unit		Number of
Units		Weighted  Average
Grant-Date Fair Value
Per Unit
Unvested awards as of December 31, 20212.0 $30.92 2.2 $13.57 
Awards granted0.4 43.54 0.6 18.31 
Awards vested(0.5)29.95 (0.4)15.89 
Awards forfeited(0.1)30.31 (0.3)14.10 
Unvested awards as of December 31, 20221.8 $34.29 2.1 $14.21 
The following table summarizes the weighted average grant-date fair value per unit award granted:
Years Ended December 31,
202220212020
Sunoco LP$43.54 $37.72 $28.63 
USAC18.31 14.92 12.55 
The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2022, 2021 and 2020 was $26 million, $24 million, and $16 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date. As of December 31, 2022, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $42 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.2 years.
10.INCOME TAXES:
As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes.
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The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:
Years Ended December 31, Years Ended December 31,
2017 2016 2015 202220212020
Current expense (benefit):     Current expense (benefit):
Federal$53
 $18
 $(274)Federal$— $19 $(6)
State(18) (35) (51)State17 24 32 
ForeignForeign— — 1 
Total35
 (17) (325)Total17 43 27 
Deferred expense (benefit):     Deferred expense (benefit):
Federal(1,723) (173) 231
Federal239 246 176 
State192
 4
 (29)State(58)(106)41 
ForeignForeign6 1 (7)
Total(1,531) (169) 202
Total187 141 210 
Total income tax benefit$(1,496) $(186) $(123)
Total income tax expenseTotal income tax expense$204 $184 $237 
Historically, our effective tax rate has differed from the statutory rate primarily due to Partnershippartnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2017, 20162022, 2021 and 20152020 is as follows:
Years Ended December 31,
202220212020
Income tax expense at United States statutory rate$1,275 $1,443 $79 
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax(1,086)(1,211)88 
Noncontrolling interests26 — 16 
State tax, net of federal tax benefit19 85 58 
Statutory rate change(42)(46)— 
Valuation allowance(4)(63)— 
Uncertain tax positions(3)(34)— 
Dividend received deduction(3)(4)— 
Foreign taxes6 1 (7)
Other16 13 3 
Income tax expense$204 $184 $237 
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 Years Ended December 31,
 2017 2016* 2015*
Income tax expense at United States statutory rate of 35 percent$352
 $139
 $479
Increase (reduction) in income taxes resulting from:     
Partnership earnings not subject to tax(457) (504) (504)
Federal rate change(1,559) —

—
Goodwill impairments172
 223
 —
State income taxes (net of federal income tax effects)131
 (17) (37)
Dividend received deduction(14) (15) (24)
Audit settlement—
 —
 (7)
Change in tax status of subsidiary(124) —
 —
Other3
 (12) (30)
Income tax benefit$(1,496) $(186) $(123)
* As adjusted. See Note 2.Index to Financial Statements
Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The following table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
 December 31,
 20222021
Deferred income tax assets:
Net operating losses and other carryforwards$603 $803 
Other60 35 
Total deferred income tax assets663 838 
Valuation allowance(19)(34)
Net deferred income tax assets644 804 
Deferred income tax liabilities:
Property, plant and equipment(218)(314)
Investments in affiliates(4,010)(4,042)
Trademarks(89)(79)
Other(28)(17)
Total deferred income tax liabilities(4,345)(4,452)
Net deferred income taxes$(3,701)$(3,648)
 December 31,
 2017 2016
Deferred income tax assets:   
Net operating losses and alternative minimum tax credit$604
 $380
Pension and other postretirement benefits21
 30
Long-term debt14
 32
Other93
 84
Total deferred income tax assets732
 526
Valuation allowance(189) (118)
Net deferred income tax assets$543
 $408
    
Deferred income tax liabilities:   
Property, plant and equipment$(664) $(1,054)
Investment in unconsolidated affiliates(2,664) (3,728)
Other(98) (20)
Total deferred income tax liabilities(3,426) (4,802)
Net deferred income taxes$(2,883) $(4,394)

The table below provides a rollforwardAs of the net deferred income tax liability as follows:
 December 31,
 2017 2016
Net deferred income tax liability, beginning of year$(4,394) $(4,082)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)—
 (460)
Tax provision1,531
 169
Other(20) (21)
Net deferred income tax liability, end of year$(2,883) $(4,394)
December 31, 2022, ETP Holdco and other corporate subsidiaries havehad a federal net operating loss carryforward of $1.57$2.4 billion, all of which $645 million will expire in 20312036 through 2037. Our corporate subsidiaries have $622037 while the remaining can be carried forward indefinitely. A total of $341 million of the federal alternative minimum tax credits atnet operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss, the amount utilized in a particular year may be limited. As of December 31, 2017,2022, Sunoco Retail LLC, a corporate subsidiary of Sunoco LP, had a state net operating loss carryforward of $84 million, which $29 million is expectedwe expect to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. fully utilize. Sunoco Retail LLC has no federal net operating loss carryforward.
Our corporate subsidiaries have state net operating loss carryforward benefits of $210$82 million, net of federal tax, some of which expire between 20182023 and 2036.2041, while others are carried forward indefinitely. Our corporate subsidiaries have cumulative excess business interest expense of $169 million available for carryforward indefinitely, of which $41 million is limited under IRC §382. A valuation allowance of $186$3 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania and the remaining $3 millionPennsylvania. A separate valuation allowance of $15 million is applicableattributable to the federal net operating loss carryforward benefit.foreign tax credits.
The following table sets forth the changes in unrecognized tax benefits:
Years Ended December 31, Years Ended December 31,
2017 2016 2015 202220212020
Balance at beginning of year$615
 $610
 $440
Balance at beginning of year$56 $90 $94 
Additions attributable to tax positions taken in the current year—
 8
 —
Additions attributable to tax positions taken in prior years28
 18
 178
Reduction attributable to tax positions taken in prior years(25) (20) —
Reduction attributable to tax positions taken in prior years(4)(34)— 
Lapse of statute(9) (1) (8)Lapse of statute— — (4)
Balance at end of year$609
 $615
 $610
Balance at end of year$52 $56 $90 
As of December 31, 2017,2022, we have $605had $52 million ($57648 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017,2022, we recognized interest and penalties of less than $3$2 million. At December 31, 2017,2022, we have interest and penalties accrued of $9$18 million, net of tax.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in this litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2017.
In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel has until April 4, 2018subsequently
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filed a petition for writ of certiorari with the U.S.United States Supreme Court.Court, and this was denied on June 11, 2018. Certain Pennsylvania taxpayers have subsequently undertaken litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. On December 22, 2021, the Pennsylvania Supreme Court found in General Motors Corporation v. Commonwealth (“GM”) that the taxpayer was entitled to meaningful backwards looking relief under the Due Process Clause, meaning the Commonwealth must equalize the taxpayer’s position with taxpayers who were not affected by the NOL cap in place for the year at issue. The Court therefore held the taxpayer was entitled to a refund by calculating its tax for that year with an uncapped NOL deduction. We believe the Pennsylvania Supreme Court’s ruling in GM will more likely than not be upheld if challenged by the Commonwealth. ETC Sunoco Inc. haspreviously recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However,In addition, based upon the Pennsylvania Supreme Court’s

October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we haveETC Sunoco previously reserved $27$34 million ($2127 million after federal income tax benefits) against the receivable. Subsequent to the Pennsylvania Supreme Court’s decision in GM, the reserve has been reversed and the entire tax benefit of $34 million ($27 million after federal income tax benefit) has been recognized by the Partnership.
In general, ETP and its subsidiaries are no longer subject toThe Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc.Service. In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2017 and prior tax years prior to 2007.years.
Sunoco, Inc. has been examinedUSAC is currently under examination by the IRS for tax years through 2013. However, statutes remain open for tax years 20072019 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.
ETP2020. Energy Transfer and its other subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
On December 22, 2017,
11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Winter Storm Impacts
Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Tax CutsPartnership’s consolidated net income and Jobs Act was signed into law. Among other provisions,also affected the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefitresults of $1.56 billionoperations in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Residual Support Agreement – AmeriGas
In connection with the closingcertain segments. The recognition of the contributionimpacts of its propane operations in January 2012, ETP previously provided contingent residual supportWinter Storm Uri during 2021 required management to make certain estimates and assumptions, including estimates of certain debt obligationsexpected credit losses and assumptions related to the resolution of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.
Guarantee of Sunoco LP Notes
In connectiondisputes with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LPcounterparties with respect to (i) $800certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.
FERC Proceedings
Rover – FERC - Stoneman House
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million principal amountcivil penalty for alleged violations of 6.375% senior notes due 2023FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued by Sunoco LP, (ii) $800 million principal amountan order on January 20, 2022 setting the matter for hearing before an administrative law judge. The hearing was set to commence on March 6, 2023.
On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of 6.25% senior notes due 2021 issued by Sunoco LPTexas seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the federal district court case. On May 24, 2022, the District Court ordered a stay of the FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. Energy Transfer and Rover intend to vigorously defend this claim.
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Rover – FERC - Tuscarawas
In December 2016, Retail Holdings contributed its interestsmid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in Sunoco LP, alongthe drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the assignmentinvestigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the guaranteeFERC regulations that Enforcement Staff intended to recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Sunoco LP’s senior notes,Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. The primary contractor (and one of the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.
Other FERC Proceedings
By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding. On December 16, 2022, the FERC issued its order on Panhandle’s rate case. On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes17, 2023, Panhandle filed its request for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, includingrehearing in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respectproceeding.
On July 1, 2022, Transwestern filed a rate case pursuant to such payment obligation, and holdersSection 4 of the notes are still owed amountsNatural Gas Act. By order dated September 9, 2022, a procedural schedule was adopted in respectthis proceeding, setting the commencement of the principal of such notes. ETC M-A will not otherwise be subjecthearing for June 22, 2023 with an initial decision anticipated by November 15, 2023. By a subsequent order dated February 14, 2023, the procedural schedule was suspended based on representations that the participants have reached an agreement in principle to the covenants of the indenture governing the notes.resolve all issues in this proceeding and a settlement is being prepared for filing at FERC.
FERC Audit
In March 2016,May 2021, the FERC commenced an audit of TrunklineSPLP for the period from January 1, 20132018 to present to evaluate Trunkline’sSPLP’s compliance with the requirements of its FERC gas tariff,oil tariffs, the accounting regulationsrequirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annualForm No. 6 reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETPEnergy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP

Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on itsthe Partnership’s financial position or results of operations.
ETP’sOur joint venture agreements require that it funds itswe fund our proportionate share of capital contributions to itsour unconsolidated affiliates. Such contributions will depend upon ETP’sthe unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment,rights-of-way (“ROW”) commitments, which require fixed monthly rental payments and either expire upon our chosen abandonment or at various dates through 2034.in the future. The following table below reflects rentalROW expense under these operating leases included in operating expenses in the accompanying consolidated statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:operations:
Years Ended December 31,
202220212020
ROW expense$64 $48 $47 
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  Years Ended December 31,
  2017 2016 2015
Rental expense(1)
 $90
 $81
 $176
Less: Sublease rental income —
 (1) (16)
Rental expense, net $90
 $80
 $160
(1)
Includes contingent rentals totaling $26 million for the year ended December 31, 2015.
Future minimum lease commitments for such leases are:Table of Contents
Index to Financial Statements
Years Ending December 31: 
2018$39
201936
202037
202130
202223
Thereafter92
Future minimum lease commitments257
Less: Sublease rental income(8)
Net future minimum lease commitments$249
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. NaturalDue to the flammable and combustible nature of natural gas and crude oil, are flammable and combustible. Seriousthe potential exists for personal injury and significantand/or property damage can ariseto occur in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
We or our subsidiaries are parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
As of December 31, 2022 and 2021, accruals of approximately $200 million and $144 million, respectively, were reflected on our consolidated balance sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $750 million.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The sections below also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed below, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.
Dakota Access Pipeline
On July 25,27, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against(“District Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that challengedallowed the legalitypipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the permits issued forDistrict Court vacated the construction ofeasement and ordered the Dakota Access pipeline across those waterwaysPipeline to be shut down and claimed violationsemptied of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescindoil by August 5, 2020. Dakota Access and the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a

request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.
After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.
The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. CircuitDistrict of Columbia (“Court of Appeals”) which granted an administrative stay of the District Court’s July 6 order and filed an emergency motion inordered further briefing on whether to fully stay the United StatesJuly 6 order. On August 5, 2020, the Court of Appeals 1) granted a stay of the portion of the District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.
In December 2016, the Department of the Army announced that although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement torequired Dakota Access allowingto shut the pipeline down and empty it of oil, 2) denied a motion to cross Lake Oahe. Almost immediately,stay the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved forMarch 25 order pending a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims baseddecision on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.
The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiatedmerits by the SRST. Several individual membersCourt of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor ofAppeals as to whether the USACE would be required to prepare an EIS, and Dakota Access. In particular,3) denied a motion to stay the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whetherDistrict Court’s order to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipelineeasement during this reviewappeal process. On October 11, 2017,The August 5 order also states that the Court issued an order allowingof Appeals expected the pipelineUSACE to remain in operation during
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clarify its position with respect to whether USACE intended to allow the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline duringnotwithstanding the remand process. First, Dakota Access must retain an independent auditor to review its compliance withvacatur of the conditionseasement and regulations governing its easements and to assess integrity threats tothat the pipeline. The auditor’s report is required to be filed withDistrict Court may consider additional relief, if necessary.
On August 10, 2020, the District Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes andordered the USACE to revise and finalizesubmit a status report by August 31, 2020, clarifying its emergency spill response planning forposition with regard to its decision-making process with respect to the sectioncontinued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side ofat the Lake Oahe crossing.crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The first report wasTribes subsequently filed with the court on December 29, 2017.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similara motion seeking an injunction to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing.
While we believe that the pending lawsuits are unlikely to halt or suspendstop the operation of the pipeline we cannot assureand both USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.
On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this outcome. Wesame January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General (December 17, 2021) and the Tribes (December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.
The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. On May 21, 2021, the District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.
The pipeline continues to operate pending completion of the EIS. Energy Transfer anticipates the draft EIS will be completed and published by the USACE in the Spring of 2023, subject to additional delays by the USACE. The release of the draft EIS was paused following the SRST’s withdrawal as a cooperating agency on January 20, 2022. However, the pause has since been lifted and the USACE expects to release the draft EIS in the spring of 2023. Energy Transfer cannot determine when or how thesefuture lawsuits will be resolved or the impact they may have on the Dakota Access project. Bakken pipelines; however, Energy Transfer expects after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate.

In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’sBelvieu LP’s (“Lone Star”), now known as Energy Transfer Mont Belvieu NGLs LP, facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells.wells at the North Terminal that has not been returned to service. Lone Star is still quantifyinghas obtained payment for most of the extent of its incurredlosses it has submitted to the adjacent operator. Lone Star continues to quantify and ongoing damages and has or will be seekingseek reimbursement for theseoutstanding losses.
MTBE Litigation
ETC Sunoco Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry,and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices.practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2017,2022, Sunoco Inc. is a defendantDefendants are defendants in sevenfour cases, including one case each initiated by the StatesState of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P.,
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ETO, ETP Holdco, Corporation, and Sunoco Partners Marketing & Terminals L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland., now known as Energy Transfer Marketing & Terminals L.P.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation Filed By or Against Williams
Following the January 26, 2015 announcementIn April and May 2016, The William Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, LE GP, LLC, and, in one of the Regency-ETPlawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Energy Transfer Defendants”), alleging that Energy Transfer Defendants breached their obligations under the Energy Transfer-Williams merger agreement (the “Regency Merger”“Merger Agreement”). In general, Williams alleges that Energy Transfer Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), purported Regency unitholders filed lawsuits(b) issuing the Partnership’s Series A convertible preferred units (the “Issuance”), and (c) making allegedly untrue representations and warranties in statethe Merger Agreement.
After a two-day trial on June 20 and federal courts21, 2016, the Court ruled in Dallasfavor of Energy Transfer Defendants and Delaware assertingissued a declaratory judgment that Energy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims relatingrelated to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of ChanceryIssuance nor certain of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP,alleged untrue representations and the members of Regency’s board of directors (the “Regency Litigation Defendants”).
The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith.warranties. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20,23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. Energy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to Energy Transfer for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause.
Trial was held regarding the parties’ amended claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court subsequently awarded Williams approximately $190 million in attorneys’ fees, expenses and pre-judgment interest.
On September 21, 2022, the Court entered a final judgment against the Energy Transfer Defendants in the amount of approximately $601 million plus post-judgment interest at a rate of 3.5% per year. The Energy Transfer Defendants filed the notice of appeal of this matter on October 21, 2022 and filed their opening brief in support of their appeal on December 30, 2022. Williams filed their answering brief on January 20, 2023, and the Energy Transfer Defendants filed their reply brief on February 6, 2023.
Rover - State of Ohio
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (together “the Ohio EPA”) filed suit against Rover and five other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the judgmentOhio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.
On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each
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filed their respective motions. Briefing on those motions was completed on November 4, 2022. The motions remain pending before the court.
Chester County, Pennsylvania Investigation
In December 2018, the former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines.
Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the prescribed time period.
In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.
On April 22, 2021, the Chester County DA filed a Complaint and Consent Decree in the Court of Chancery.Common Pleas of Chester County, Pennsylvania constituting a settlement agreement between the Chester County DA and the Partnership. A status conference was held on May 10, 2021, and an Amended Consent Decree was filed on June 16, 2021, which was approved and entered by the Court on December 20, 2021. In accordance with the terms of the Amended Consent Decree, when the Mariner East 2/Mariner East 2X pipelines reached the point of mechanical completion in Chester County on March 23, 2022, the Amended Consent Decree terminated, which the Partnership communicated to the Chester County DA via letter on March 29, 2022. A Joint Motion for Termination of the Amended Consent Decree was filed on August 26, 2022. On May 5, 2017, PlaintiffJanuary 14, 2023, the Court entered an Order terminating the Amended Consent Decree dated December 20, 2021. This matter is now closed.
Shareholder Litigation Regarding Pipeline Construction
Various purported unitholders of Energy Transfer have filed derivative actions against various past and current members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s Partnership Agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et at., Case No. 2022-0139-SG (Del. Ch.); Elliot v. LE GP LLC, Case No. 3:22-cv-01527-B (N.D. Tex.); Chapa v. Kelcy L. Warren, et al., Index No. 611307/2022 (N.Y. Sup. Ct.); Elliott v. LE GP et al, Cause No. DC-22-14194 (Dallas County, Tex.); and King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The King action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:20-cv-00719-X) has been consolidated with the Bettiol action. On August 9, 2022, the Elliot action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:22-cv-01527-B) was voluntarily dismissed.
Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors, Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an Amended Verified Class Action Complaint.amended complaint and added as additional defendants Energy Transfer directors Marshall McCrea and Matthew Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The Regency Litigation Defendants thenamended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed Motionsa motion to Dismissdismiss ACERS’ amended complaint. On April 6, 2021, the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order grantingcourt granted in part and denyingdenied in part the motionsdefendants’ motion to dismiss,dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against all defendants other than Regency GP,McReynolds, McGinn, and Hennigan. Fact discovery is ongoing. On August 23, 2022, the Court granted in part and denied in part ACERS’ motion for class certification. The Court certified a class consisting of those who purchased or otherwise acquired common units of Energy Transfer between February 25, 2017 and November 11, 2019.
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On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and Messrs. Warren, Long, McCrea, and Whitehurst. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims for violations of Sections 10(b) and Regency GP LLC.20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of the Rover pipeline project.
On August 10, 2022, the Court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. Defendants filed their motion to dismiss the amended complaint on November 4, 2022. On November 7, 2022, the court granted Defendants’ motion to transfer and transferred this action to the United States District Court for the Northern District of Texas.
The Regency Litigation Defendantsdefendants cannot predict the outcome of the Regency Merger Litigationthese lawsuits or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendantsdefendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.
Cline Class Action
On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M), LLC (now known as Energy Transfer (R&M), LLC) and Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.
After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.
On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10, 2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the district court to enter a final judgment in compliance with the Rules. ETMT also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction in part. The injunction has since been lifted.
Despite the fact that ETMT has taken the position that the judgment is not final and not subject to execution, the Class engaged in asset discovery and actively tried to collect on the judgment through garnishment proceedings from ETMT’s customers. ETMT unsuccessfully tried to deposit the funds into the Court’s Registry. Accordingly, to stop the garnishment proceedings, on December 2, 2022, ETMT wired approximately $161 million to the Plaintiff’s approved Plan Administrator, which represents the full amount of the judgment with attorney’s fees and post-judgment interest. ETMT did so without waiving its ability to pursue its pending appeal or its right to appeal the merits of the judgment. Plaintiff has since dismissed the garnishment actions.
ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the Regency Merger Litigation.appeal. A Petition for Writ of Certiorari was filed with the United States Supreme Court on April 28, 2022, seeking review of the 10th Circuit’s dismissal of ETMT’s appeal. The Regency LitigationSupreme Court denied ETMT’s Petition on October 3, 2022. Despite the denial of its Petition for Writ of Certiorari, ETMT is still vigorously appealing the finality issues underlying the Order and has appealed the denial of the Motion to Modify to the 10th Circuit in an attempt to get a decision on finality. The appeal to the 10th Circuit has been fully briefed and oral argument is set for March 21, 2023.
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Energy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.
On April 8, 2022, Energy Transfer and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower,” and together with Culberson and Culberson Equity, “Defendants”). On October 1, 2018, ETC and Culberson entered into a Gas Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to require Energy Transfer to purchase their respective interests in Culberson for approximately $93 million. On April 8, 2022, Plaintiffs filed suit against Defendants believeasserting claims for declaratory judgment and breach of contract. Plaintiffs contend that Defendants materially breached the Regency Merger LitigationBypass GGPA by sending some committed gas to third parties and also by failing to send any gas to Plaintiffs since March 2020, and thus that Defendants' put notice is without meritvoid. Defendants have answered the lawsuit. Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and intendattorneys’ fees. Culberson Equity and Moontower also filed a counterclaim against Energy Transfer for (1) breach of the Option Agreement, and (2) a declaratory judgment concerning Energy Transfer’s alleged obligation to vigorously defendpurchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court in Dallas County, Texas. On April 27, 2022, Defendants filed an application for a temporary restraining order, temporary injunction, and permanent injunction. The Court held a hearing on the application on April 28 and denied the injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation, to which Plaintiffs objected. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an appraisal process regarding the put price. An independent appraiser was appointed and issued his decision on October 15, 2022, concluding that the put price totals $93 million. Plaintiffs have consistently reiterated their objection to the appraisal process. Defendants filed a motion for summary judgment, but the Court has postponed considering it until the spring of 2023, after further document discovery and depositions. On December 7, 2022, Plaintiffs amended their petition to add a claim against itall Defendants for fraudulent inducement. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and any othersexpense that maywill be required to resolve it.
Massachusetts Attorney General v. New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the Regency Merger.

Enterprise Products Partners, L.P.merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P.together with NEG and Enterprise Products Operating LLC (collectively, “Enterprise”SUG, “Respondents”) and Enbridge (US) Inc.  Trial resulted inretained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU. Specifically, the MA AG seeks a verdict in favor of ETP against Enterprise that consisted of $319refund to NEG’s ratepayers for approximately $18 million in compensatory damageslegal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and $595 millionreconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50 percent) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in disgorgement2011, the Hearing Officer deferred decision on the motion to ETP.dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA AG failed to take any further steps to prosecute its claims for nearly seven years. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014,case remained largely dormant until February 2022, when the trial courtHearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recoveryprocedural schedule on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of AppealsMarch 16, 2022 (which was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is due February 26, 2018.
Sunoco Logistics Merger Litigation
Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”)amended slightly on August 22, 2022). The ETP Unitholder Plaintiffs allege causes of action challenging the mergerparties are now actively engaged in discovery and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”).preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The ETP Unitholder Plaintiffs sought rescissionMA AG served three sets of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costsdiscovery requests on Respondents on September 9, September 12, and attorneys’ fees.September 20, respectively, to which Respondents timely responded. On October 5, 2017,2022, the ETP-SXL DefendantsMA AG requested that the DPU issue a ruling on whether the information that Respondents redacted in their attorneys’ fees invoices is protected by the attorney-client privilege. On the same day, the MA AG also filed a Motion to DismissStay the ETP Unitholder Plaintiffs’ claims. Rather thanProcedural Schedule pending a ruling on the privilege issue. On October 6, 2022, without even affording Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the Motionprocedural schedule.
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Accordingly, all previous deadlines (including the ETP Unitholder Plaintiffs choseMA AG’s October 7, 2022, deadline to voluntarily dismiss their claims without prejudice in November 2017.
The ETP-SXL Defendantssubmit direct pre-filed testimony) are presently stayed. Respondents cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what theultimate outcome of any such lawsuits might be. Northis regulatory proceeding, nor can the ETP-SXL Defendantsthey predict the amount of time and expense that wouldwill be required to resolve such lawsuits. The ETP-SXL Defendants believethese claims; however, Respondents will vigorously defend themselves against the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.
SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.
On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.
On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2017 and 2016, accruals of approximately $33 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our December 31, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.MA AG’s claims.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in

February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certain•certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be heldcontractually responsible for contamination caused by other parties.
Certain•certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Legacy•legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc.the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc.•the Partnership is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2017, Sunoco, Inc.2022, the Partnership had been named as a PRP at approximately 4331 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc.The Partnership is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc.The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’sthe Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The following table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not
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have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
December 31,
 20222021
Current$54 $46 
Non-current228 247 
Total environmental liabilities$282 $293 
 December 31,
 2017 2016
Current$36
 $26
Non-current314
 283
Total environmental liabilities$350
 $309
In 2013, weWe have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 20172022 and 2016,2021, the Partnership recorded $23$30 million and $43$28 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
Our pipeline operations are subject to regulation by the United States Department of TransportationDOT under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
In January 2012, we experienced a release on our products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which we are obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. We also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. We have also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, we received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to our West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of our Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. The case went to Hearing in November 2016 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows, or financial position.
In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on our Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. We do not expect there to be a material impact to our results of operations, cash flows or financial position.
Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for

OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

12.REVENUE:
Disaggregation of revenue
The major types of revenue within our reportable segments, are as follows:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP;
•fuel distribution and marketing;
•all other;
•investment in USAC;
•contract operations;
•retail parts and services; and
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•all other.
Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606.
Intrastate transportation and storage revenue
Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
Interstate transportation and storage revenue
Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
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The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed.
The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
Midstream revenue
Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported. The various types of revenue contracts our midstream segment enters into include:
Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.
Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.
Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:
•In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.
•Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.
Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.
Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency
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fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.
Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers.
NGL and refined products transportation and services revenue
Our NGL and refined products transportation and services segment’s revenues are primarily derived from transportation, fractionation, blending and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
Crude oil transportation and services revenue
Our crude oil transportation and services segment’s revenues are primarily derived from providing transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed.
Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
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Sunoco LP’s fuel distribution and marketing revenue
Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method.
Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized.
Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer.
Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor is recognized ratably over the term of the underlying lease.
Sunoco LP’s all other revenue
Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided).
USAC’s contract operations revenue
USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years; however, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.
Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.
USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees charged to customers or using expected cost plus margin.
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The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date.
There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration.
USAC’s retail parts and services revenue
USAC’s retail parts and services revenue is primarily earned on directly reimbursable freight and crane charges that are the financial responsibility of USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based on the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration.
All other revenue
Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties. These operations also include end-user coal handling facilities.
Contract Balances with Customers
The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.
The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.
The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
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The following table summarizes the consolidated activity of our contract liabilities:
12.DERIVATIVE ASSETS AND LIABILITIES:Contract Liabilities
Balance, December 31, 2020$309 
Additions849 
Revenue recognized(699)
Balance, December 31, 2021459 
Additions1,113 
Revenue recognized(944)
Other(13)
Balance, December 31, 2022$615 
The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2022 and 2021 were as follows:
December 31,
 20222021
Contract Balances  
Contract asset$200 $157 
Accounts receivable from contracts with customers834 463 
Costs to Obtain or Fulfill a Contract
Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in the future and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the years ended December 31, 2022, 2021 and 2020 was $22 million, $21 million and $18 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.
Performance Obligations
At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the following table.
Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately ten years, with an estimated volume-weighted term remaining of approximately five years.
Sunoco LP is party to a 15-year take-or-pay fuel supply agreement in which the distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall, Sunoco LP will recognize the amount payable by the distributor at the sooner of the time at which the distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations.
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In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.
As of December 31, 2022, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $39.20 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
Years Ending December 31,
202320242025ThereafterTotal
Revenue expected to be recognized on contracts with customers existing as of December 31, 2022$7,038 $6,023 $5,158 $20,982 $39,201 
Practical Expedients Utilized by the Partnership
The Partnership elected the following practical expedients in accordance with Topic 606:
•Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.
•Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
•Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.
•Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.
•Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.
•Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).
•Variable consideration of wholly unsatisfied performance obligations:The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.
13.LEASE ACCOUNTING:
Lessee Accounting
The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.
At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities,
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operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.
Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.
To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.
Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.
For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of December 31, 2022 and 2021 were as follows:
December 31,
20222021
Operating leases:
Lease right-of-use assets, net$808 $826 
Operating lease current liabilities45 47 
Accrued and other current liabilities1 1 
Non-current operating lease liabilities798 814 
Finance leases:
Property, plant and equipment, net$1 $1 
Lease right-of-use assets, net11 12 
Accrued and other current liabilities— 1 
Current maturities of long-term debt2 3 
Long-term debt, less current maturities9 9 
Other non-current liabilities1 1 
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The components of lease expense for the years ended December 31, 2022 and 2021 were as follows:
Year Ended December 31,
Income Statement Location20222021
Operating lease costs:
Operating lease costCost of goods sold$3 $10 
Operating lease costOperating expenses63 78 
Operating lease costSelling, general and administrative22 17 
Total operating lease costs88 105 
Finance lease costs:
Amortization of lease assetsDepreciation, depletion and amortization— 1 
Interest on lease liabilitiesInterest expense, net of capitalized interest— 1 
Total finance lease costs— 2 
Short-term lease costOperating expenses33 40 
Variable lease costOperating expenses13 9 
Lease costs, gross134 156 
Less: Sublease incomeOther revenue40 45 
Lease costs, net$94 $111 
The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2022 and 2021 were as follows:
December 31,
20222021
Weighted-average remaining lease term (years):
Operating leases2119
Finance leases2729
Weighted-average discount rate (%):
Operating leases5 %5 %
Finance leases4 %4 %
Cash flows and non-cash activity related to leases for the years ended December 31, 2022 and 2021 were as follows:
Year Ended December 31,
20222021
Operating cash flows from operating leases$(133)$(147)
Lease assets obtained in exchange for new finance lease liabilities1 9 
Lease assets obtained in exchange for new operating lease liabilities41 9 
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Maturities of lease liabilities as of December 31, 2022 are as follows:
Operating leasesFinance leasesTotal
2023$86 $3 $89 
202481 1 82 
202579 — 79 
202677 — 77 
202771 — 71 
Thereafter1,027 15 1,042 
Total lease payments1,421 19 1,440 
Less: present value discount578 6 584 
Present value of lease liabilities$843 $13 $856 
Lessor Accounting
Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.
Sunoco LP’s future minimum operating lease payments receivable as of December 31, 2022 are as follows:
Lease Payments
2023$67 
202447 
202545 
202643 
202741 
Thereafter25 
Total undiscounted cash flows$268 
14.DERIVATIVE ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peakoff-peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
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We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:
December 31, 2022December 31, 2021
Notional
Volume		MaturityNotional
Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures145 2023585 2022-2023
Basis Swaps IFERC/NYMEX(1)
(39,563)2023(66,665)2022
Power (Megawatt):
Forwards— 2023-2029653,000 2023-2029
Futures(21,384)2023(604,920)2022-2023
Options – Puts119,200 2023(7,859)2022
Options – Calls— —(30,932)2022
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX42,440 2023-20246,738 2022-2023
Swing Swaps IFERC(202,815)2023-2024(106,333)2022-2023
Fixed Swaps/Futures(15,758)2023-2025(63,898)2022-2023
Forward Physical Contracts2,423 2023-2024(5,950)2023
NGL (MBbls) – Forwards/Swaps6,934 2023-20258,493 2022-2024
Crude (MBbls) – Forwards/Swaps795 2023-20243,672 2022-2023
Refined Products (MBbls) – Futures(3,547)2023-2024(3,349)2022-2023
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX(37,448)2023(40,533)2022
Fixed Swaps/Futures(37,448)2023(40,533)2022
Hedged Item – Inventory37,448 202340,533 2022
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
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 December 31, 2017 December 31, 2016
 
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives       
(Trading)       
Natural Gas (BBtu):       
Fixed Swaps/Futures1,078
 2018 (683) 2017
Basis Swaps IFERC/NYMEX(1)
48,510
 2018-2020 2,243
 2017
Options – Calls13,000
 2018 —
 —
Power (Megawatt):       
Forwards435,960
 2018-2019 391,880
 2017-2018
Futures(25,760) 2018 109,564
 2017-2018
Options – Puts(153,600) 2018 (50,400) 2017
Options – Calls137,600
 2018 186,400
 2017
Crude (MBbls) – Futures—
 — (617) 2017
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX4,650
 2018-2020 10,750
 2017-2018
Swing Swaps IFERC87,253
 2018-2019 (5,663) 2017
Fixed Swaps/Futures(4,700) 2018-2019 (52,653) 2017-2019
Forward Physical Contracts(145,105) 2018-2020 (22,492) 2017
Natural Gas Liquid (MBbls) – Forwards/Swaps6,679
 2018-2019 (5,787) 2017
Refined Products (MBbls) – Futures(3,783) 2018-2019 (2,240) 2017
Fair Value Hedging Derivatives       
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX(39,770) 2018 (36,370) 2017
Fixed Swaps/Futures(39,770) 2018 (36,370) 2017
Hedged Item – Inventory39,770
 2018 36,370
 2017
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
Term
Type(1)
Notional Amount Outstanding
December 31, 2022December 31, 2021
July 2022 (2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate$— $400 
July 2023 (2)(3)
Forward-starting to pay a fixed rate of 3.845% and receive a floating rate— 200 
July 2024 (2)
Forward-starting to pay a fixed rate of 3.512% and receive a floating rate400 200 
Term 
Type(1)
 Notional Amount Outstanding
December 31, 2017 December 31, 2016
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1)Floating rates are based on either SOFR or three-month LIBOR.
(1)
(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
(3)This interest rate swap was terminated and settled in 2022.
Floating rates are based on 3-month LIBOR.
(2)
Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
TheOur natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers,industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

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Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
Fair Value of Derivative InstrumentsFair Value of Derivative Instruments
Asset Derivatives Liability DerivativesAsset DerivativesLiability Derivatives
December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016December 31, 2022December 31, 2021December 31, 2022December 31, 2021
Derivatives designated as hedging instruments:       Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)$14
 $—
 $(2) $(4)Commodity derivatives (margin deposits)$87 $46 $(7)$(3)
14
 —
 (2) (4)87 46 (7)(3)
Derivatives not designated as hedging instruments:       Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)262
 338
 (281) (416)Commodity derivatives (margin deposits)506 173 (411)(156)
Commodity derivatives44
 24
 (55) (52)Commodity derivatives95 53 (108)(52)
Interest rate derivatives—
 —
 (219) (193)Interest rate derivatives— — (23)(387)
Embedded derivatives in Legacy ETP Preferred Units—
 —
 —
 (1)
306
 362
 (555) (662)601 226 (542)(595)
Total derivatives$320
 $362
 $(557) $(666)Total derivatives$688 $272 $(549)$(598)
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
 Asset Derivatives Liability DerivativesAsset DerivativesLiability Derivatives
 Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016Balance Sheet LocationDecember 31, 2022December 31, 2021December 31, 2022December 31, 2021
Derivatives without offsetting agreements Derivative liabilities $—
 $—
 $(219) $(194)Derivatives without offsetting agreementsDerivative liabilities$— $— $(23)$(387)
Derivatives in offsetting agreements:Derivatives in offsetting agreements:        Derivatives in offsetting agreements:
OTC contracts Derivative assets (liabilities) 44
 24
 (55) (52)OTC contractsDerivative assets (liabilities)95 53 (108)(52)
Broker cleared derivative contracts Other current assets (liabilities) 276
 338
 (283) (420)Broker cleared derivative contractsOther current assets (liabilities)593 219 (418)(159)
 320
 362
 (557) (666)688 272 (549)(598)
Offsetting agreements:Offsetting agreements:        Offsetting agreements:
Counterparty netting Derivative assets (liabilities) (20) (4) 20
 4
Counterparty nettingDerivative assets (liabilities)(85)(43)85 43 
Counterparty netting Other current assets (liabilities) (263) (338) 263
 338
Counterparty nettingOther current assets (liabilities)(359)(150)359 150 
Total net derivativesTotal net derivatives $37
 $20
 $(274) $(324)Total net derivatives$244 $79 $(105)$(405)
We disclose the non-exchange traded financial derivative instruments as price risk managementderivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.settlement.

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The following tables summarize the amounts recognized with respect to our derivative financial instruments:
Location of Gain (Loss) Recognized in Income on DerivativesAmount of Gain (Loss) Recognized in Income on Derivatives
Years Ended December 31,
202220212020
Derivatives not designated as hedging instruments:
Commodity derivatives – TradingCost of products sold$83 $(6)$8 
Commodity derivatives – Non-tradingCost of products sold41 (141)(34)
Interest rate derivativesGains (losses) on interest rate derivatives293 61 (203)
Total$417 $(86)$(229)
15.RETIREMENT BENEFITS:
 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
   Years Ended December 31,
   2017 2016 2015
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivativesCost of products sold $26
 $14
 $21
Total  $26
 $14
 $21
 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives
   Years Ended December 31,
   2017 2016 2015
Derivatives not designated as hedging instruments:       
Commodity derivatives – TradingCost of products sold $31
 $(35) $(11)
Commodity derivatives – Non-tradingCost of products sold 3
 (173) 23
Interest rate derivativesLosses on interest rate derivatives (37) (12) (18)
Embedded derivativesOther, net 1
 4
 12
Total  $(2) $(216) $6

13.RETIREMENT BENEFITS:
Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees.employees, including those of Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $38$79 million, $44$65 million and $39$35 million to these 401(k) savings plans for the years ended December 31, 2017, 2016,2022, 2021 and 2015,2020, respectively.
As a result of the economic conditions in 2020, effective June 8, 2020, the Partnership ceased employer matching and profit sharing contributions through December 31, 2020. The Partnership resumed all such contributions in 2021.
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Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2017, 2016 and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.

Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The fundingCertain of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension andPartnership’s subsidiaries sponsor pension and/or other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.plans that provide benefits to a defined group of retirees. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
December 31, 2022December 31, 2021
Pension BenefitsPension Benefits
Funded PlansUnfunded PlansOther Postretirement BenefitsFunded PlansUnfunded PlansOther Postretirement Benefits
Change in benefit obligation:
Benefit obligation at beginning of period$50 $26 $195 $55 $31 $208 
Service cost— — 1 — — 1 
Interest cost1 1 4 1 1 4 
Benefits paid, net(1)(3)(14)(2)(4)(16)
Actuarial gain and other(8)(3)(38)(2)(2)(2)
Settlements— — — (2)— — 
Energy Transfer Canada sale(20)(2)— — — — 
Benefit obligation at end of period22 19 148 50 26 195 
Change in plan assets:
Fair value of plan assets at beginning of period44 — 311 45 — 291 
Return on plan assets and other(4)— (41)2 — 26 
Employer contributions1 — 3 1 — 10 
Benefits paid, net(1)— (14)(2)— (16)
Settlements— — — (2)— — 
Energy Transfer Canada sale(20)— — — — — 
Fair value of plan assets at end of period20 — 259 44 — 311 
Amount underfunded (overfunded) at end of period$2 $19 $(111)$6 $26 $(116)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets$— $— $127 $— $— $138 
Current liabilities— (3)(2)— (4)(2)
Non-current liabilities(2)(16)(14)(6)(22)(20)
$(2)$(19)$111 $(6)$(26)$116 
Amounts recognized in accumulated other comprehensive income (pre-tax basis) consist of:
Net actuarial gain (loss)$— $(2)$5 $— $1 $(27)
Prior service cost (credit)— — (3)— — 19 
$— $(2)$2 $— $1 $(8)
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 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Change in benefit obligation:           
Benefit obligation at beginning of period$18
 $51
 $165
 $20
 $57
 $180
Interest cost1
 1
 4
 1
 2
 4
Amendments—
 —
 7
 —
 —
 —
Benefits paid, net(2) (6) (20) (1) (7) (21)
Actuarial (gain) loss and other2
 1
 (1) (2) (1) 2
Settlements(18) —
 —
 —
 —
 —
Benefit obligation at end of period1
 47
 155
 18
 51
 165
            
Change in plan assets:           
Fair value of plan assets at beginning of period12
 —
 248
 15
 —
 253
Return on plan assets and other3
 —
 11
 (2) —
 6
Employer contributions6
 —
 10
 —
 —
 10
Benefits paid, net(2) —
 (20) (1) —
 (21)
Settlements(18) —
 —
 —
 —
 —
Fair value of plan assets at end of period1
 —
 249
 12
 —
 248
            
Amount underfunded (overfunded) at end of period$—
 $47
 $(94) $6
 $51
 $(83)
            
Amounts recognized in the consolidated balance sheets consist of:           
Non-current assets$—
 $—
 $120
 $—
 $—
 $108
Current liabilities—
 (8) (2) —
 (7) (2)
Non-current liabilities—
 (39) (24) (6) (44) (23)
 $—
 $(47) $94
 $(6) $(51) $83
            
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:           
Net actuarial gain$—
 $5
 $(17) $—
 $—
 $(12)
Prior service cost—
 —
 20
 —
 —
 14
 $—
 $5
 $3
 $—
 $—
 $2
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Index to Financial Statements
The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
December 31, 2017 December 31, 2016December 31, 2022December 31, 2021
Pension Benefits   Pension Benefits  Pension BenefitsPension Benefits
Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement BenefitsFunded PlansUnfunded PlansOther Postretirement BenefitsFunded PlansUnfunded PlansOther Postretirement Benefits
Projected benefit obligation$1
 $47
 N/A
 $18
 $51
 N/A
Projected benefit obligation$22 $19 N/A$50 $26 N/A
Accumulated benefit obligation1
 47
 $155
 18
 51
 $165
Accumulated benefit obligation22 19 148 50 26 195 
Fair value of plan assets1
 —
 249
 12
 —
 248
Fair value of plan assets20 — 259 44 — 311 
Components of Net Periodic Benefit Cost
December 31, 2022December 31, 2021
Pension BenefitsOther Postretirement BenefitsPension BenefitsOther Postretirement Benefits
Net periodic benefit cost:Net periodic benefit cost:
Service costService cost$— $1 $— $1 
Interest costInterest cost2 4 2 4 
Expected return on plan assetsExpected return on plan assets(2)(11)(2)(11)
Prior service cost amortizationPrior service cost amortization— 19 — 19 
December 31, 2017 December 31, 2016
Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net periodic benefit cost:       
Interest cost$2
 $4
 $3
 $4
Expected return on plan assets—
 (9) (1) (8)
Prior service cost amortization—
 2
 —
 1
Settlements—
 —
 —
 —
Net periodic benefit cost$2
 $(3) $2
 $(3)Net periodic benefit cost$— $13 $— $13 
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:following table:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.27% 2.34% 3.65% 2.34%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
December 31, 2022December 31, 2021
Pension BenefitsOther Postretirement BenefitsPension BenefitsOther Postretirement Benefits
Discount rate5.00 %2.46 %2.79 %2.24 %
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:following table:
December 31, 2017 December 31, 2016December 31, 2022December 31, 2021
Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement BenefitsPension BenefitsOther Postretirement BenefitsPension BenefitsOther Postretirement Benefits
Discount rate3.52% 3.10% 3.60% 3.06%Discount rate2.70 %2.58 %2.57 %2.18 %
Expected return on assets:       Expected return on assets:
Tax exempt accounts3.50% 7.00% 3.50% 7.00%Tax exempt accounts7.00 %7.00 %4.76 %7.00 %
Taxable accountsN/A
 4.50% N/A
 4.50%Taxable accounts— 4.75 %— 4.75 %
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
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The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefitthe plans are shown in the table below:following table:
 December 31,December 31,
 2017 2016 20222021
Health care cost trend rate 7.20% 6.73%Health care cost trend rate7.48 %7.14 %
Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.99% 4.96%Rate to which the cost trend is assumed to decline (the ultimate trend rate)5.18 %4.95 %
Year that the rate reaches the ultimate trend rate 2023
 2021
Year that the rate reaches the ultimate trend rate20302028
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%.
The investment strategy of ETC Sunoco Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, ETC Sunoco Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
Fair Value Measurements at December 31, 2022
 Fair Value TotalLevel 1Level 2Level 3
Asset Category:    
Cash and cash equivalents$2 $2 $— $— 
Mutual funds (1)
18 18 — — 
Total$20 $20 $— $— 
(1)Comprised of approximately 100% equities as of December 31, 2022.
Fair Value Measurements at December 31, 2021
 Fair Value TotalLevel 1Level 2Level 3
Asset Category:    
Cash and cash equivalents$1 $1 $— $— 
Mutual funds (1)
24 24 — — 
Fixed income securities19 — 19 — 
Total$44 $25 $19 $— 
(1)Comprised of approximately 100% equities as of December 31, 2021.
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   Fair Value Measurements at December 31, 2017
 Fair Value Total Level 1 Level 2 Level 3
Asset category:       
Mutual funds(1)
$1
 $1
 $—
 $—
Total$1
 $1
 $—
 $—
(1)
Comprised of approximately 100% equities as of December 31, 2017.
Table of Contents
   Fair Value Measurements at December 31, 2016
 Fair Value Total Level 1 Level 2 Level 3
Asset category:       
Mutual funds(1)
$12
 $12
 $—
 $—
Total$12
 $12
 $—
 $—
Index to Financial Statements
(1)
Comprised of approximately 100% equities as of December 31, 2016.

The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:
Fair Value Measurements at December 31, 2022
Fair Value TotalLevel 1Level 2Level 3
Asset category:
Cash and cash equivalents$19 $19 $— $— 
Mutual funds(1)
146 146 — — 
Fixed income securities94 — 94 — 
Total$259 $165 $94 $— 
   Fair Value Measurements at December 31, 2017
 Fair Value Total Level 1 Level 2 Level 3
Asset category:       
Cash and cash equivalents$33
 $33
 $—
 $—
Mutual funds(1)
146
 146
 —
 —
Fixed income securities70
 —
 70
 —
Total$249
 $179
 $70
 $—
(1)
Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017.
(1)Primarily composed of market index funds as of December 31, 2022.
  Fair Value Measurements at December 31, 2016Fair Value Measurements at December 31, 2021
Fair Value Total Level 1 Level 2 Level 3Fair Value TotalLevel 1Level 2Level 3
Asset category:       Asset category:
Cash and cash equivalents$23
 $23
 $—
 $—
Cash and cash equivalents$22 $22 $— $— 
Mutual funds(1)
134
 134
 —
 —
Mutual funds(1)
175 175 — — 
Fixed income securities91
 —
 91
 —
Fixed income securities114 — 114 — 
Total$248
 $157
 $91
 $—
Total$311 $197 $114 $— 
(1)
(1)Primarily composed of market index funds as of December 31, 2021.
Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.
The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. 
Contributions
We expect to contribute $8$5 million to pension plans and $10$1 million to other postretirement plans in 2018.2023. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Panhandle and Sunoco, Inc.’sThe Partnership’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:following table:
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
(1)     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
YearsPension Benefits - Funded PlansPension Benefits - Unfunded PlansOther Postretirement Benefits (Gross, Before Medicare Part D)
2023$1 $4 $16 
20241 3 15 
20251 3 15 
20261 2 14 
20271 2 13 
2028 – 20327 6 55 
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
PanhandleThe Partnership does not expect to receive any Medicare Part D subsidies in any future periods.


16.REPORTABLE SEGMENTS:
14.RELATED PARTY TRANSACTIONS:
In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.
ETE previously paid us to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. These agreements expired in 2016.
The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.
The following table summarizes the affiliate revenues on our consolidated statements of operations:
 Years Ended December 31,
 2017 2016 2015
Affiliated revenues$697
 $377
 $417
The following table summarizes the related company balances on our consolidated balance sheets:
 December 31,
 2017 2016
Accounts receivable from related companies:   
ETE$—
 $22
Sunoco LP219
 96
FGT11
 15
Other88
 76
Total accounts receivable from related companies$318
 $209
    
Accounts payable to related companies:   
Sunoco LP195
 20
Other14
 23
Total accounts payable to related companies$209
 $43
 December 31,
 2017 2016
Long-term notes receivable (payable) – related companies:   
Sunoco LP$85
 $87
Phillips 66—
 (250)
Net long-term notes receivable (payable) – related companies$85
 $(163)


15.REPORTABLE SEGMENTS:
Our financial statementsreportable segments currently reflect the following reportable segments, which conduct their business primarily in the United States, as follows:States:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
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•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services; and
•all other.
The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the LP;
•investment in USAC; and
•all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.other.
Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation terminalling and other fees. Revenues from our crude oil transportation and services segment are reflected in crude sales and gathering, transportation and other fees. Revenues from our investment in Sunoco LP segment are primarily reflected in cruderefined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in refined productnatural gas sales.
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflectsreflect amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

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The following tables present financial information by segment:
Years Ended December 31,
202220212020
Revenues:
Intrastate transportation and storage:
Revenues from external customers$6,954 $7,307 $2,312 
Intersegment revenues864 1,264 232 
7,818 8,571 2,544 
Interstate transportation and storage:
Revenues from external customers2,185 1,802 1,841 
Intersegment revenues66 39 20 
2,251 1,841 1,861 
Midstream:
Revenues from external customers4,114 2,620 1,944 
Intersegment revenues12,987 8,696 3,082 
17,101 11,316 5,026 
NGL and refined products transportation and services:
Revenues from external customers21,414 16,989 8,501 
Intersegment revenues4,243 2,972 2,012 
25,657 19,961 10,513 
Crude oil transportation and services:
Revenues from external customers25,980 17,442 11,674 
Intersegment revenues2 4 5 
25,982 17,446 11,679 
Investment in Sunoco LP:
Revenues from external customers25,677 17,571 10,653 
Intersegment revenues52 25 57 
25,729 17,596 10,710 
Investment in USAC:
Revenues from external customers689 621 655 
Intersegment revenues16 12 12 
705 633 667 
All other:
Revenues from external customers2,863 3,065 1,374 
Intersegment revenues711 411 464 
3,574 3,476 1,838 
Eliminations(18,941)(13,423)(5,884)
Total revenues$89,876 $67,417 $38,954 
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 Years Ended December 31,
 2017 2016 2015
Revenues:     
Intrastate transportation and storage:     
Revenues from external customers$2,891
 $2,155
 $1,912
Intersegment revenues192
 458
 338
 3,083
 2,613
 2,250
Interstate transportation and storage:     
Revenues from external customers915
 946
 1,008
Intersegment revenues19
 23
 17
 934
 969
 1,025
Midstream:     
Revenues from external customers2,510
 2,342
 2,607
Intersegment revenues4,433
 2,837
 2,449
 6,943
 5,179
 5,056
NGL and refined products transportation and services:     
Revenues from external customers8,326
 5,973
 4,569
Intersegment revenues322
 436
 428
 8,648
 6,409
 4,997
Crude oil transportation and services:     
Revenues from external customers11,672
 7,539
 8,980
Intersegment revenues31
 —
 —
 11,703
 7,539
 8,980
All other:     
Revenues from external customers2,740
 2,872
 15,216
Intersegment revenues161
 400
 558
 2,901
 3,272
 15,774
Eliminations(5,158) (4,154) (3,790)
Total revenues$29,054
 $21,827
 $34,292
Years Ended December 31,
202220212020
Cost of products sold:
Intrastate transportation and storage$6,000 $4,769 $1,478 
Interstate transportation and storage25 11 — 
Midstream12,682 8,569 2,598 
NGL and refined products transportation and services21,656 16,248 7,139 
Crude oil transportation and services22,917 14,759 8,838 
Investment in Sunoco LP24,350 16,246 9,654 
Investment in USAC111 85 82 
All other3,328 3,068 1,527 
Eliminations(18,837)(13,360)(5,829)
Total cost of products sold$72,232 $50,395 $25,487 
Years Ended December 31,
202220212020
Depreciation, depletion and amortization:
Intrastate transportation and storage$209 $191 $185 
Interstate transportation and storage513 457 411 
Midstream1,351 1,190 1,140 
NGL and refined products transportation and services865 778 667 
Crude oil transportation and services663 588 640 
Investment in Sunoco LP193 177 189 
Investment in USAC237 239 239 
All other133 197 207 
Total depreciation, depletion and amortization$4,164 $3,817 $3,678 
Years Ended December 31,
202220212020
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage$17 $20 $18 
Interstate transportation and storage175 140 17 
Midstream19 24 24 
NGL and refined products transportation and services42 51 60 
Crude oil transportation and services— 10 (2)
All other4 1 2 
Total equity in earnings of unconsolidated affiliates$257 $246 $119 
F - 73
Table of Contents
Index to Financial Statements
Years Ended December 31,
202220212020
Segment Adjusted EBITDA:Segment Adjusted EBITDA:
Intrastate transportation and storageIntrastate transportation and storage$1,396 $3,483 $863 
Interstate transportation and storageInterstate transportation and storage1,753 1,515 1,680 
MidstreamMidstream3,210 1,868 1,670 
NGL and refined products transportation and servicesNGL and refined products transportation and services3,025 2,828 2,802 
Crude oil transportation and servicesCrude oil transportation and services2,187 2,023 2,258 
Investment in Sunoco LPInvestment in Sunoco LP919 754 739 
Investment in USACInvestment in USAC426 398 414 
All OtherAll Other177 177 105 
Adjusted EBITDA (consolidated)Adjusted EBITDA (consolidated)$13,093 $13,046 $10,531 
Years Ended December 31,
2017 2016 2015
Cost of products sold:     
Intrastate transportation and storage$2,327
 $1,897
 $1,554
Midstream4,761
 3,381
 3,264
NGL and refined products transportation and services6,508
 4,553
 3,431
Crude oil transportation and services9,826
 6,416
 8,158
All other2,509
 2,942
 14,029
Eliminations(5,130) (4,109) (3,722)
Total cost of products sold$20,801
 $15,080
 $26,714

Years Ended December 31,
202220212020
Reconciliation of net income to Adjusted EBITDA:
Net income$5,868 $6,687 $140 
Depreciation, depletion and amortization4,164 3,817 3,678 
Interest expense, net of interest capitalized2,306 2,267 2,327 
Income tax expense204 184 237 
Impairment losses and other386 21 2,880 
(Gains) losses on interest rate derivatives(293)(61)203 
Non-cash compensation expense115 111 121 
Unrealized (gains) losses on commodity risk management activities(42)(162)71 
Inventory valuation adjustments(5)(190)82 
Losses on extinguishments of debt— 38 75 
Adjusted EBITDA related to unconsolidated affiliates565 523 628 
Equity in earnings of unconsolidated affiliates(257)(246)(119)
Impairment of investments in unconsolidated affiliates— — 129 
Other, net82 57 79 
Adjusted EBITDA (consolidated)$13,093 $13,046 $10,531 
December 31,
202220212020
Segment assets:
Intrastate transportation and storage$6,609 $7,322 $6,308 
Interstate transportation and storage17,979 17,774 17,582 
Midstream21,851 21,960 18,583 
NGL and refined products transportation and services27,903 28,160 21,423 
Crude oil transportation and services19,200 19,649 17,960 
Investment in Sunoco LP6,830 5,815 5,267 
Investment in USAC2,666 2,768 2,949 
All other and eliminations2,605 2,515 5,072 
Total segment assets$105,643 $105,963 $95,144 
F - 74
Table of Contents
Index to Financial Statements
Years Ended December 31,
Years Ended December 31,202220212020
2017 2016 2015
Depreciation, depletion and amortization:     
Additions to property, plant and equipment (1):
Additions to property, plant and equipment (1):
Intrastate transportation and storage$147
 $144
 $129
Intrastate transportation and storage$179 $52 $49 
Interstate transportation and storage214
 207
 210
Interstate transportation and storage644 159 150 
Midstream954
 840
 720
Midstream1,004 484 487 
NGL and refined products transportation and services401
 355
 290
NGL and refined products transportation and services507 751 2,403 
Crude oil transportation and services402
 251
 218
Crude oil transportation and services246 343 291 
Investment in Sunoco LPInvestment in Sunoco LP186 174 124 
Investment in USACInvestment in USAC169 60 119 
All other214
 189
 362
All other91 135 136 
Total depreciation, depletion and amortization$2,332
 $1,986
 $1,929
Total additions to property, plant and equipment (1)
Total additions to property, plant and equipment (1)
$3,026 $2,158 $3,759 
 Years Ended December 31,
 2017 2016 2015
Equity in earnings (losses) of unconsolidated affiliates:     
Intrastate transportation and storage$(156) $35
 $32
Interstate transportation and storage236
 193
 197
Midstream20
 19
 (19)
NGL and refined products transportation and services33
 41
 29
Crude oil transportation and services4
 (4) (9)
All other19
 (225) 239
Total equity in earnings of unconsolidated affiliates$156
 $59
 $469
 Years Ended December 31,
 2017 2016 2015
Segment Adjusted EBITDA:     
Intrastate transportation and storage$626
 $613
 $543
Interstate transportation and storage1,098
 1,117
 1,155
Midstream1,481
 1,133
 1,237
NGL and refined products transportation and services1,641
 1,496
 1,179
Crude oil transportation and services1,379
 834
 521
All other487
 540
 882
Total Segment Adjusted EBITDA6,712
 5,733
 5,517
Depreciation, depletion and amortization(2,332) (1,986) (1,929)
Interest expense, net(1,365) (1,317) (1,291)
Gains on acquisitions—
 83
 —
Impairment losses(920) (813) (339)
Losses on interest rate derivatives(37) (12) (18)
Non-cash unit-based compensation expense(74) (80) (79)
Unrealized gains (losses) on commodity risk management activities56
 (131) (65)
Inventory valuation adjustments—
 —
 58
Losses on extinguishments of debt(42) —
 (43)
Adjusted EBITDA related to unconsolidated affiliates(984) (946) (937)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Other, net148
 115
 23
Income before income tax benefit$1,005
 $397
 $1,366

 December 31,
 2017 2016 2015
Assets:     
Intrastate transportation and storage$5,020
 $5,176
 $4,882
Interstate transportation and storage13,518
 10,833
 11,345
Midstream20,004
 17,873
 17,039
NGL and refined products transportation and services17,600
 14,074
 11,568
Crude oil transportation and services17,736
 15,909
 10,941
All other4,087
 6,240
 9,353
Total assets$77,965
 $70,105
 $65,128
 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Intrastate transportation and storage$175
 $76
 $105
Interstate transportation and storage726
 280
 866
Midstream1,308
 1,255
 2,174
NGL and refined products transportation and services2,971
 2,198
 2,853
Crude oil transportation and services453
 1,841
 1,358
All other268
 160
 811
Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis)$5,901
 $5,810
 $8,167
 December 31,
 2017 2016 2015
Advances to and investments in unconsolidated affiliates:     
Intrastate transportation and storage$85
 $399
 $406
Interstate transportation and storage2,118
 2,149
 2,516
Midstream126
 111
 117
NGL and refined products transportation and services234
 235
 258
Crude oil transportation and services22
 18
 21
All other1,231
 1,368
 1,685
Total advances to and investments in unconsolidated affiliates$3,816
 $4,280
 $5,003


16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is(1)Amounts are presented below. The sumon the accrual basis, net of net income per Limited Partner unit by quarter does not equalcontributions in aid of constructions costs. Amounts exclude acquisitions and include only the net income per limited partner unit for the year due to the computationPartnership’s proportionate share of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts.
  Quarters Ended  
  March 31* June 30* September 30* December 31 Total Year
2017:          
Revenues $6,895
 $6,576
 $6,973
 $8,610
 $29,054
Operating income 683
 736
 779
 199
 2,397
Net income 393
 296
 715
 1,097
 2,501
Common Unitholders’ interest in net income (loss) 32
 (49) 335
 668
 986
Basic net income (loss) per Common Unit $0.03
 $(0.04) $0.29
 $0.57
 $0.94
Diluted net income (loss) per Common Unit $0.03
 $(0.04) $0.29
 $0.57
 $0.93
  Quarters Ended  
  March 31* June 30* September 30* December 31* Total Year*
2016:          
Revenues $4,481
 $5,289
 $5,531
 $6,526
 $21,827
Operating income 598
 708
 594
 (139) 1,761
Net income 360
 465
 94
 (336) 583
Common Unitholders’ interest in net income (loss) (71) 58
 (252) (754) (1,019)
Basic net income (loss) per Common Unit $(0.11) $0.06
 $(0.34) $(0.97) $(1.38)
Diluted net income (loss) per Common Unit $(0.11) $0.06
 $(0.34) $(0.97) $(1.38)
* As adjusted. See Note 2. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.
The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $920 million and $813 million, respectively. Impairment losses in 2017 were primarilycapital expenditures related to our Trunkline, SUG Holdings, CDM, Sea Robin and refined products reporting units. Impairment losses in 2016 were primarily related to our PEPL reporting unit, Sea Robin reporting unit and midstream midcontinent operations. The three months ended December 31, 2017 and September 30, 2016 reflected the recognition of a non-cash impairment of our investments in subsidiaries of $313 million and $308 million, respectively, in our interstate transportation and storage segment.joint ventures.
For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.

17.CONSOLIDATING GUARANTOR FINANCIAL INFORMATION
Prior to the Sunoco Logistics Merger, Sunoco Logistics Partners Operations L.P., a subsidiary of Sunoco Logistics was the issuer of multiple series of senior notes that were guaranteed by Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company.
These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting. To present the supplemental condensed consolidating financial information on a comparable basis, the prior period financial information has been recast as if the Sunoco Logistics Merger occurred on January 1, 2015.
The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:
December 31,
202220212020
Investments in unconsolidated affiliates:
Intrastate transportation and storage$139 $110 $89 
Interstate transportation and storage2,201 2,209 2,278 
Midstream54 101 110 
NGL and refined products transportation and services446 476 509 
Crude oil transportation and services— — 22 
All other53 51 52 
Total investments in unconsolidated affiliates$2,893 $2,947 $3,060 
F - 75
 December 31, 2017
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents$—
 $(3) $309
 $—
 $306
All other current assets—
 159
 6,063
 —
 6,222
Property, plant and equipment—
 —
 58,437
 —
 58,437
Investments in unconsolidated affiliates48,378
 11,648
 3,816
 (60,026) 3,816
All other assets—
 —
 9,184
 —
 9,184
Total assets$48,378
 $11,804
 $77,809
 $(60,026) $77,965
          
Current liabilities(1,496) (3,660) 12,150
 —
 6,994
Non-current liabilities21,604
 7,607
 7,609
 —
 36,820
Noncontrolling interest—
 —
 5,882
 —
 5,882
Total partners’ capital28,270
 7,857
 52,168
 (60,026) 28,269
Total liabilities and equity$48,378
 $11,804
 $77,809
 $(60,026) $77,965
 December 31, 2016
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents$—
 $41
 $319
 $—
 $360
All other current assets—
 2
 5,281
 —
 5,283
Property, plant and equipment—
 —
 50,917
 —
 50,917
Investments in unconsolidated affiliates23,350
 10,664
 4,280
 (34,014) 4,280
All other assets—
 5
 9,260
 —
 9,265
Total assets$23,350
 $10,712
 $70,057
 $(34,014) $70,105
          
Current liabilities(1,761) (3,800) 11,764
 —
 6,203
Non-current liabilities299
 7,313
 30,148
 (299) 37,461
Noncontrolling interest—
 —
 1,232
 —
 1,232
Total partners’ capital24,812
 7,199
 26,913
 (33,715) 25,209
Total liabilities and equity$23,350
 $10,712
 $70,057
 $(34,014) $70,105

 Year Ended December 31, 2017
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $—
 $29,054
 $—
 $29,054
Operating costs, expenses, and other—
 1
 26,656
 —
 26,657
Operating income (loss)—
 (1) 2,398
 —
 2,397
Interest expense, net—
 (156) (1,209) —
 (1,365)
Equity in earnings of unconsolidated affiliates2,564
 1,242
 156
 (3,806) 156
Impairment of investments in unconsolidated affiliate—
 —
 (313) —
 (313)
Losses on interest rate derivatives—
 —
 (37) —
 (37)
Other, net—
 —
 168
 (1) 167
Income before income tax benefit2,564
 1,085
 1,163
 (3,807) 1,005
Income tax benefit—
 —
 (1,496) —
 (1,496)
Net income2,564
 1,085
 2,659
 (3,807) 2,501
Less: Net income attributable to noncontrolling interest—
 —
 420
 —
 420
Net income attributable to partners$2,564
 $1,085
 $2,239
 $(3,807) $2,081
          
Other comprehensive income (loss)$—
 $—
 $(5) $—
 $(5)
Comprehensive income2,564
 1,085
 2,654
 (3,807) 2,496
Comprehensive income attributable to noncontrolling interest—
 —
 420
 —
 420
Comprehensive income attributable to partners$2,564
 $1,085
 $2,234
 $(3,807) $2,076

 Year Ended December 31, 2016
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $—
 $21,827
 $—
 $21,827
Operating costs, expenses, and other—
 1
 20,065
 —
 20,066
Operating income (loss)—
 (1) 1,762
 —
 1,761
Interest expense, net—
 (157) (1,160) —
 (1,317)
Equity in earnings of unconsolidated affiliates554
 863
 59
 (1,417) 59
Impairment of investment in unconsolidated affiliate—
 —
 (308) —
 (308)
Losses on interest rate derivatives—
 —
 (12) —
 (12)
Other, net—
 —
 214
 —
 214
Income before income tax benefit554
 705
 555
 (1,417) 397
Income tax benefit—
 —
 (186) —
 (186)
Net income554
 705
 741
 (1,417) 583
Less: Net income attributable to noncontrolling interest—
 —
 41
 —
 41
Net income attributable to partners$554
 $705
 $700
 $(1,417) $542
          
Other comprehensive income$—
 $—
 $4
 $—
 $4
Comprehensive income554
 705
 745
 (1,417) 587
Comprehensive income attributable to noncontrolling interest—
 —
 41
 —
 41
Comprehensive income attributable to partners$554
 $705
 $704
 $(1,417) $546


 Year Ended December 31, 2015
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $—
 $34,292
 $—
 $34,292
Operating costs, expenses, and other—
 1
 32,064
 —
 32,065
Operating income (loss)—
 (1) 2,228
 —
 2,227
Interest expense, net—
 (133) (1,158) —
 (1,291)
Equity in earnings of unconsolidated affiliates1,441
 526
 469
 (1,967) 469
Losses on interest rate derivatives—
 —
 (18) —
 (18)
Other, net—
 —
 (21) —
 (21)
Income before income tax benefit1,441
 392
 1,500
 (1,967) 1,366
Income tax benefit—
 —
 (123) —
 (123)
Net income1,441
 392
 1,623
 (1,967) 1,489
Less: Net income attributable to noncontrolling interest—
 —
 53
 —
 53
Net income attributable to partners$1,441
 $392
 $1,570
 $(1,967) $1,436
          
Other comprehensive income$—
 $—
 $60
 $—
 $60
Comprehensive income1,441
 392
 1,683
 (1,967) 1,549
Comprehensive income attributable to noncontrolling interest—
 —
 53
 —
 53
Comprehensive income attributable to partners$1,441
 $392
 $1,630
 $(1,967) $1,496
 Year Ended December 31, 2017
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$2,564
 $1,047
 $4,681
 $(3,807) $4,485
Cash flows from investing activities(2,240) (1,368) (5,672) 3,807
 (5,473)
Cash flows from financing activities(324) 277
 981
 —
 934
Change in cash—
 (44) (10) —
 (54)
Cash at beginning of period—
 41
 319
 —
 360
Cash at end of period$—
 $(3) $309
 $—
 $306
 Year Ended December 31, 2016
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$553
 $675
 $3,492
 $(1,417) $3,303
Cash flows from investing activities(976) (2,400) (4,431) 1,417
 (6,390)
Cash flows from financing activities423
 1,729
 768
 —
 2,920
Change in cash—
 4
 (171) —
 (167)
Cash at beginning of period—
 37
 490
 —
 527
Cash at end of period$—
 $41
 $319
 $—
 $360

 Year Ended December 31, 2015
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$1,441
 $388
 $2,886
 $(1,968) $2,747
Cash flows from investing activities(2,271) (1,815) (5,702) 1,968
 (7,820)
Cash flows from financing activities830
 1,363
 2,744
 —
 4,937
Change in cash—
 (64) (72) —
 (136)
Cash at beginning of period—
 101
 562
 —
 663
Cash at end of period$—
 $37
 $490
 $—
 $527





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