Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
ýQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) For the quarterly period ended March 31, 2023
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
or
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
etlogoa05.jpg
ENERGY TRANSFER EQUITY, L.P.LP
(Exact name of registrant as specified in its charter)
Delaware30-0108820
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code)
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
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerýAccelerated filer¨☐
Non-accelerated filer
¨  (Do not check if a smaller reporting company)
Smaller reporting company¨☐
Emerging growth company¨☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨☐     No  ý
At November 3, 2017,April 28, 2023, the registrant had 1,079,185,0303,096,774,774 Common Units outstanding.


Table of Contents
FORM 10-Q
ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
TABLE OF CONTENTS
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets
15
Consolidated Statements of Operations
37
Consolidated Statements of Comprehensive Income
48
Consolidated StatementStatements of Equity
59
Consolidated Statements of Cash Flows
610
Notes to Consolidated Financial Statements
711
1. Organization and Basis of Presentation
11
2. Acquisitions
11
3. Cash and Cash Equivalents
11
4. Inventories
12
5. Fair Value Measurements
12
6. Net Income Per Common Unit
15
7. Debt Obligations
15
8. Redeemable Noncontrolling Interests
16
9. Equity
16
10. Regulatory Matters, Commitments, Contingencies and Environmental Liabilities
18
11. Revenue
27
12. Derivative Assets and Liabilities
28
13. Reportable Segments
32
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
4236
Recent Developments
36
Results of Operations
38
Liquidity and Capital Resources
49
Cash Distributions
52
5956
6157
6158
6258
6258
6360



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Definitions
Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity”References to the “Partnership” or “ETE”) in periodic press releases and some oral statements of“Energy Transfer” refer to Energy Transfer Equity officials during presentations aboutLP. In addition, 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,” “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 or expressed, forecasted, projected 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 “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2016 filed with the Securities and Exchange Commission on February 24, 2017 and “Part II — Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed on May 4, 2017.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
/dper day
AmeriGasAmeriGas Partners, L.P.
AOCI
AOCIaccumulated other comprehensive income (loss)
Bblsbarrels
Btu
BBtubillion British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy contentunits
DOJU.S. Department of Justice
EPAEnvironmental Protection Agency
ETLP Credit Facility
CitrusCitrus, LLC, a 50/50 joint venture which owns Florida Gas Transmission Company, LLC, which owns the Florida Gas Transmission Pipeline
Dakota AccessDakota Access, LLC, a non-wholly-owned subsidiary of Energy Transfer and/or Dakota Access Pipeline
Energy Transfer CanadaEnergy Transfer Canada ULC, a non-wholly-owned subsidiary of Energy Transfer until its sale in August 2022
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)
ETC SunocoETC Sunoco Holdings LLC (formerly Sunoco, Inc.), a wholly-owned subsidiary of Energy Transfer
ETOEnergy Transfer LP’s $3.75 billion revolving credit facilityOperating, L.P., formerly a non-wholly-owned subsidiary of Energy Transfer until its merger into the Partnership in April 2021
ETPEnergy Transfer Partners, L.P. subsequent to the close of the merger of Sunoco Logistics Partners L.P. and Energy 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
Exchange ActSecurities Exchange Act of 1934, as amended
FERCExplorerExplorer Pipeline Company
FERCFederal Energy Regulatory Commission
GAAPaccounting principles generally accepted in the United States of America
IDRsincentive distribution rights
Lake Charles LNGLake Charles LNG Company, LLC
LIBOR
General PartnerLE GP, LLC, the general partner of Energy Transfer
HFOTCOHFOTCO LLC, a wholly-owned subsidiary of Energy Transfer which owns the Houston Terminal
IFERCInside FERC’s Gas Market Report
LIBORLondon Interbank Offered Rate
MMBtumillion British thermal units
MTBEmethyl tertiary butyl ether
NGL
MBblsthousand barrels
MEPMidcontinent Express Pipeline LLC
NGLnatural gas liquid, such as propane, butane and natural gasoline
NYMEXNew York Mercantile Exchange
OSHAFederal Occupational Safety and Health Act
OTCover-the-counter

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Panhandle
NYMEXNew York Mercantile Exchange
OTCover-the-counter
PanhandlePanhandle Eastern Pipe Line Company, LP, a wholly-owned subsidiary of Energy Transfer and/or Panhandle Eastern Pipe Line
PCBspolychlorinated biphenyl
PESPartnership AgreementPhiladelphia Energy SolutionsTransfer’s Third Amended and Restated Agreement of Limited Partnership, as amended to date
PennTexPHMSAPennTex Midstream Partners, LPPipeline and Hazardous Materials Safety Administration
Preferred UnitsETP Series A cumulative convertible preferred units
RegencyRegency Energy Partners LP
Rover
RoverRover Pipeline LLC, a non-wholly-owned subsidiary of Energy Transfer and/or Rover Pipeline
SEC
SECSecurities and Exchange Commission
Series A Convertible Preferred UnitsETE6.250% Series A convertible preferred unitsFixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Sunoco LogisticsSeries B Preferred UnitsSunoco Logistics Partners L.P.6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Sunoco LPSeries C Preferred UnitsSunoco LP (previously named Susser Petroleum Partners, LP)7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
TranswesternSeries 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
SOFRSecured overnight financing rate
SPLPSunoco Pipeline L.P., a wholly-owned subsidiary of Energy Transfer
TranswesternTranswestern Pipeline Company, LLC, a wholly-owned subsidiary of Energy Transfer and/or Transwestern Pipeline
TrunklineTrunkline Gas Company, LLC
WMBUSACThe Williams Companies, Inc.USA Compression Partners, LP, a publicly traded partnership and consolidated subsidiary of Energy Transfer
White CliffsWhite Cliffs Pipeline, L.L.C.
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, 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, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects 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 —– FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
March 31,
2023		December 31,
2022
ASSETS
Current assets:
Cash and cash equivalents$330 $257 
Accounts receivable, net8,269 8,466 
Accounts receivable from related companies108 93 
Inventories2,047 2,461 
Income taxes receivable64 68 
Derivative assets6 10 
Other current assets546 726 
Total current assets11,370 12,081 
Property, plant and equipment106,643 105,996 
Accumulated depreciation and depletion(26,639)(25,685)
Property, plant and equipment, net80,004 80,311 
Investments in unconsolidated affiliates2,861 2,893 
Lease right-of-use assets, net813 819 
Other non-current assets, net1,585 1,558 
Intangible assets, net5,322 5,415 
Goodwill2,566 2,566 
Total assets$104,521 $105,643 
The accompanying notes are an integral part of these consolidated financial statements.
5
 September 30, 2017 December 31, 2016
ASSETS   
Current assets:   
Cash and cash equivalents$469
 $463
Accounts receivable, net3,551
 3,557
Accounts receivable from related companies90
 47
Inventories1,957
 2,103
Derivative assets42
 21
Other current assets433
 503
Current assets held for sale4,147
 291
Total current assets10,689
 6,985
    
Property, plant and equipment68,730
 61,158
Accumulated depreciation and depletion(9,463) (7,905)
 59,267
 53,253
    
Advances to and investments in unconsolidated affiliates3,177
 3,040
Other non-current assets, net891
 816
Intangible assets, net6,195
 5,489
Goodwill5,161
 5,170
Non-current assets held for sale—
 4,258
Total assets$85,380
 $79,011
Table of Contents


ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Dollars in million)
(unaudited)

March 31,
2023		December 31,
2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$6,934 $6,952 
Accounts payable to related companies9 17 
Derivative liabilities4 23 
Operating lease current liabilities45 45 
Accrued and other current liabilities3,168 3,329 
Current maturities of long-term debt2 2 
Total current liabilities10,162 10,368 
Long-term debt, less current maturities47,229 48,260 
Non-current derivative liabilities43 23 
Non-current operating lease liabilities791 798 
Deferred income taxes3,759 3,701 
Other non-current liabilities1,374 1,341 
Commitments and contingencies
Redeemable noncontrolling interests494 493 
Equity:
Limited Partners:
Preferred Unitholders6,080 6,051 
Common Unitholders27,057 26,960 
General Partner(2)(2)
Accumulated other comprehensive income13 16 
Total partners’ capital33,148 33,025 
Noncontrolling interests7,521 7,634 
Total equity40,669 40,659 
Total liabilities and equity$104,521 $105,643 
The accompanying notes are an integral part of these consolidated financial statements.
6
 September 30, 2017 December 31, 2016
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$3,994
 $3,502
Accounts payable to related companies46
 42
Derivative liabilities129
 172
Accrued and other current liabilities2,881
 2,367
Current maturities of long-term debt716
 1,194
Liabilities associated with assets held for sale81
 —
Total current liabilities7,847
 7,277
    
Long-term debt, less current maturities44,495
 42,608
Long-term notes payable – related company—
 250
Non-current derivative liabilities132
 76
Deferred income taxes5,027
 5,112
Other non-current liabilities1,218
 1,055
Liabilities associated with assets held for sale—
 68
    
Commitments and contingencies
 
Preferred units of subsidiary—
 33
Redeemable noncontrolling interests21
 15
    
Equity:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders(1,566) (1,871)
Series A Convertible Preferred Units377
 180
Total partners’ deficit(1,192) (1,694)
Noncontrolling interest27,832
 24,211
Total equity26,640
 22,517
Total liabilities and equity$85,380
 $79,011

Table of Contents
ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
(unaudited)

Three Months Ended
March 31,
20232022
REVENUES:
Refined product sales$5,454 $5,446 
Crude sales5,478 5,302 
NGL sales4,160 5,109 
Gathering, transportation and other fees2,777 2,693 
Natural gas sales899 1,753 
Other227 188 
Total revenues18,995 20,491 
COSTS AND EXPENSES:
Cost of products sold14,610 16,138 
Operating expenses1,025 949 
Depreciation, depletion and amortization1,059 1,028 
Selling, general and administrative238 230 
Impairment losses1 300 
Total costs and expenses16,933 18,645 
OPERATING INCOME2,062 1,846 
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized(619)(559)
Equity in earnings of unconsolidated affiliates88 56 
Gains (losses) on interest rate derivatives(20)114 
Other, net7 21 
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)1,518 1,478 
Income tax expense (benefit)71 (9)
NET INCOME1,447 1,487 
Less: Net income attributable to noncontrolling interests321 205 
Less: Net income attributable to redeemable noncontrolling interests13 13 
NET INCOME ATTRIBUTABLE TO PARTNERS1,113 1,269 
General Partner’s interest in net income1 1 
Preferred Unitholders’ interest in net income109 106 
Common Unitholders’ interest in net income$1,003 $1,162 
NET INCOME PER COMMON UNIT:
Basic$0.32 $0.38 
Diluted$0.32 $0.37 
The accompanying notes are an integral part of these consolidated financial statements.
7
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
REVENUES       
Natural gas sales$1,098
 $1,070
 $3,132
 $2,603
NGL sales1,749
 1,249
 4,782
 3,339
Crude sales2,273
 1,649
 6,751
 4,572
Gathering, transportation and other fees1,068
 1,028
 3,244
 3,118
Refined product sales2,706
 2,243
 7,928
 6,249
Other580
 466
 1,800
 1,346
Total revenues9,474
 7,705
 27,637
 21,227
COSTS AND EXPENSES       
Cost of products sold7,078
 5,776
 21,028
 15,430
Operating expenses636
 526
 1,779
 1,540
Depreciation, depletion and amortization632

548
 1,840
 1,596
Selling, general and administrative142
 209
 484
 515
Total costs and expenses8,488
 7,059
 25,131
 19,081
OPERATING INCOME986
 646
 2,506
 2,146
OTHER INCOME (EXPENSE)       
Interest expense, net(505) (474) (1,471) (1,336)
Equity in earnings of unconsolidated affiliates92
 49
 228
 205
Impairment of investment in an unconsolidated affiliate—
 (308) —
 (308)
Losses on extinguishments of debt—
 —
 (25) —
Losses on interest rate derivatives(8) (28) (28) (179)
Other, net76
 55
 168
 98
INCOME (LOSS) BEFORE INCOME TAX BENEFIT641
 (60) 1,378
 626
Income tax benefit(157) (89) (97) (151)
INCOME FROM CONTINUING OPERATIONS798
 29
 1,475
 777
Income (loss) from discontinued operations, net of income taxes6

12
 (264)
24
NET INCOME804
 41
 1,211
 801
Less: Net income (loss) attributable to noncontrolling interest552
 (168) 508
 39
NET INCOME ATTRIBUTABLE TO PARTNERS252
 209
 703
 762
General Partner’s interest in net income1
 —
 2
 2
Convertible Unitholders’ interest in income11
 2
 25
 3
Limited Partners’ interest in net income$240
 $207
 $676
 $757
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:       
Basic$0.22
 $0.20
 $0.64
 $0.72
Diluted$0.22
 $0.19
 $0.62
 $0.71
NET INCOME PER LIMITED PARTNER UNIT:       
Basic$0.22
 $0.20
 $0.63
 $0.72
Diluted$0.22
 $0.19
 $0.61
 $0.71

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ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
(unaudited)
Three Months Ended
March 31,
20232022
Net income$1,447 $1,487 
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities1 (5)
Actuarial gain (loss) related to pension and other postretirement benefit plans(5)7 
Foreign currency translation adjustments1 11 
Change in other comprehensive income from unconsolidated affiliates— 12 
(3)25 
Comprehensive income1,444 1,512 
Less: Comprehensive income attributable to noncontrolling interests321 210 
Less: Comprehensive income attributable to redeemable noncontrolling interests13 13 
Comprehensive income attributable to partners$1,110 $1,289 
The accompanying notes are an integral part of these consolidated financial statements.
8
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Net income$804
 $41
 $1,211
 $801
Other comprehensive income (loss), net of tax:       
Change in value of available-for-sale securities2
 —
 5
 5
Actuarial gain (loss) relating to pension and other postretirement benefit plans5
 —
 2
 (3)
Foreign currency translation adjustments—
 —
 —
 (1)
Change in other comprehensive income (loss) from unconsolidated affiliates—
 2
 (1) (9)
 7
 2
 6
 (8)
Comprehensive income811
 43
 1,217
 793
Less: Comprehensive income (loss) attributable to noncontrolling interest559
 (166) 514
 31
Comprehensive income attributable to partners$252
 $209
 $703
 $762

Table of Contents
ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTSTATEMENTS OF EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017
(Dollars in millions)
(unaudited)
Common UnitholdersPreferred UnitholdersGeneral PartnerAOCINoncontrolling InterestsTotal
Balance, December 31, 2022$26,960 $6,051 $(2)$16 $7,634 $40,659 
Distributions to partners(920)(80)(1)— — (1,001)
Distributions to noncontrolling interests— — — — (441)(441)
Capital contributions from noncontrolling interests— — — — 3 3 
Other comprehensive loss, net of tax— — — (3)— (3)
Other, net14 — — — 4 18 
Net income, excluding amounts attributable to redeemable noncontrolling interests1,003 109 1 — 321 1,434 
Balance, March 31, 2023$27,057 $6,080 $(2)$13 $7,521 $40,669 
Common UnitholdersPreferred UnitholdersGeneral PartnerAOCINoncontrolling InterestsTotal
Balance, December 31, 2021$25,230 $6,051 $(4)$23 $8,045 $39,345 
Distributions to partners(528)(80)— — — (608)
Distributions to noncontrolling interests— — — — (307)(307)
Capital contributions from noncontrolling interests— — — — 373 373 
Other comprehensive income, net of tax— — — 20 5 25 
Other, net17 — — — 10 27 
Net income, excluding amounts attributable to redeemable noncontrolling interests1,162 106 1 — 205 1,474 
Balance, March 31, 2022$25,881 $6,077 $(3)$43 $8,331 $40,329 
The accompanying notes are an integral part of these consolidated financial statements.
9
 General Partner     Common Unitholders     Series A Convertible Preferred Units Noncontrolling Interest Total    
Balance, December 31, 2016$(3) $(1,871) $180
 $24,211
 $22,517
Distributions to partners(2) (750) —
 —
 (752)
Distributions to noncontrolling interest—
 —
 —
 (2,180) (2,180)
Distributions reinvested—
 (173) 173
 —
 —
Subsidiary units issued—
 (56) (1) 1,692
 1,635
Issuance of common units—
 568
 —
 —
 568
Capital contributions received from noncontrolling interests—
 —
 —
 1,907
 1,907
PennTex unit acquisition—
 (2) —
 (278) (280)
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 —
 —
 69
 69
Sale of Bakken Pipeline interest—
 42
 —
 1,958
 2,000
Other comprehensive income, net of tax—
 —
 —
 6
 6
Other, net—
 —
 —
 (61) (61)
Net income2
 676
 25
 508
 1,211
Balance, September 30, 2017$(3) $(1,566) $377
 $27,832
 $26,640

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ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
Three Months Ended
March 31,
20232022
OPERATING ACTIVITIES:
Net income$1,447 $1,487 
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization1,059 1,028 
Deferred income taxes53 32 
Inventory valuation adjustments(29)(120)
Non-cash compensation expense37 36 
Impairment losses1 300 
Distributions on unvested awards(20)(15)
Equity in earnings of unconsolidated affiliates(88)(56)
Distributions from unconsolidated affiliates87 44 
Other non-cash2 (46)
Net change in operating assets and liabilities, net of effects of acquisitions801 (320)
Net cash provided by operating activities3,350 2,370 
INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received— (589)
Capital expenditures, excluding allowance for equity funds used during construction(853)(752)
Contributions in aid of construction costs16 20 
Distributions from unconsolidated affiliates in excess of cumulative earnings30 46 
Proceeds from sales of other assets4 4 
Net cash used in investing activities(803)(1,271)
FINANCING ACTIVITIES:
Proceeds from borrowings7,582 5,658 
Repayments of debt(8,605)(5,428)
Capital contributions from noncontrolling interests3 373 
Distributions to partners(1,001)(608)
Distributions to noncontrolling interests(441)(307)
Distributions to redeemable noncontrolling interests(12)(12)
Net cash used in financing activities(2,474)(324)
Increase in cash and cash equivalents73 775 
Cash and cash equivalents, beginning of period257 336 
Cash and cash equivalents, end of period$330 $1,111 
The accompanying notes are an integral part of these consolidated financial statements.
10
 Nine Months Ended
September 30,
 2017 2016
OPERATING ACTIVITIES   
Net income$1,211
 $801
Reconciliation of net income to net cash provided by operating activities:   
Impairment of investment in an unconsolidated affiliate—
 308
Loss (income) from discontinued operations264
 (24)
Depreciation, depletion and amortization1,840
 1,596
Deferred income taxes(120) (139)
Unit-based compensation expense76
 46
Inventory valuation adjustments(38) (203)
Equity in earnings of unconsolidated affiliates(228) (205)
Distributions from unconsolidated affiliates211
 190
Other(134) (197)
Net change in operating assets and liabilities, net of effects of acquisition222
 48
Net cash provided by operating activities3,304
 2,221
INVESTING ACTIVITIES   
Proceeds from Bakken Pipeline Transaction2,000
 —
Cash paid for acquisition of PennTex noncontrolling interest(280) —
Cash paid for acquisitions, net of cash received(293) (330)
Capital expenditures, excluding allowance for equity funds used during construction(6,102) (5,877)
Contributions to unconsolidated affiliates(230) (47)
Distributions from unconsolidated affiliates in excess of cumulative earnings115
 112
Other30
 58
Net cash used in investing activities(4,760) (6,084)
FINANCING ACTIVITIES   
Proceeds from borrowings23,988
 18,288
Repayments of long-term debt(22,586) (13,955)
Cash received from affiliate notes—
 1,606
Cash paid on affiliate notes(255) (1,607)
Subsidiary units issued for cash1,635
 2,097
Units issued for cash568
 —
Distributions to partners(752) (780)
Distributions to noncontrolling interest(2,156) (2,027)
Capital contributions received from noncontrolling interest919
 187
Other(58) 110
Net cash provided by financing activities1,303
 3,919
DISCONTINUED OPERATIONS   
Operating activities245
 168
Investing activities(82) (359)
Changes in cash included in current assets held for sale(4) 12
Net increase (decrease) in cash and cash equivalents of discontinued operations159
 (179)
Increase (decrease) in cash and cash equivalents6
 (123)
Cash and cash equivalents, beginning of period463
 581
Cash and cash equivalents, end of period$469
 $458

Table of Contents
ENERGY TRANSFER EQUITY, L.P.LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)
(unaudited)
1.ORGANIZATION AND BASIS OF PRESENTATION
1.ORGANIZATION AND BASIS OF PRESENTATION
Organization
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
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. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 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. Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. 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 Energy Transfer Partners, L.P. 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 Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.
Prior to the Sunoco Logistics Merger, ETE owned 18.4 million Energy Transfer Partners, L.P. common units (representing 3.3% of the total outstanding common units), 81 million Energy Transfer Partners, L.P. Class H units and 100 Energy Transfer Partners, L.P. Class I units. In connection with the Sunoco Logistics Merger, the Class H units were cancelled, and ETE now owns 27.5 million ETP common units (representing 2.5% of the total outstanding common units) and 100 ETP Class I units. The ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the Class I units prior to the Sunoco Logistics Merger.
At the time of 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 consolidated financial statements of ETE presented herein includecontain 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.

Business Operations
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and SunocoEnergy Transfer LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 15 for stand-alone financial information apart from that of the consolidated partnership information included herein.
Our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities 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.subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”).
Basis of Presentation
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016 included as Exhibit 99.1 to our Form 8-K2022, filed with the SEC on October 2, 2017.February 17, 2023. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
For prior periods reportedThe consolidated financial statements of the Partnership presented herein certain transactions related toinclude the businessresults of legacyoperations of our controlled subsidiaries, including Sunoco Logistics have been reclassified from costLP and USAC. The Partnership owns the general partner interest, incentive distribution rights and 28.5 million common units of products sold to operating expenses; these transactions include sales between operating subsidiariesSunoco LP, and their marketing affiliate. Additionally, there were otherthe general partner interests and 46.1 million common units of USAC.
Certain prior period amounts have been reclassified to conform to the 2017current period presentation. Other than the reclassification of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations, theseThese reclassifications had no impact on net income or total equity.
Use of Estimates
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includesrequires the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and the accrual for and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Subsidiary Common Unit Transactions
The Parent2.ACQUISITIONS
Lotus Midstream Acquisition
On May 2, 2023, Energy Transfer acquired Lotus Midstream Operations, LLC (“Lotus Midstream”) for total consideration of $900 million in cash and approximately 44.5 million newly issued Energy Transfer common units. Lotus Midstream owns and operates Centurion Pipeline Company accounts for the difference between the carrying amount of its investments in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP or Sunoco LP (excluding transactions with the Parent Company) as capital transactions.
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 thatLLC, 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 expects to adopt ASU 2014-09integrated crude midstream platform located in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard.

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements.
We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of ETP’s reportable segments as well as the accounting for certain processing contracts in ETP’s midstream operations. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.
We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income.
We have substantially completed a detailed review of revenue contracts representative of Sunoco LP’s business segments and their revenue streams; however, we continue to evaluate contract modifications and new contracts that have been or will be entered prior to the adoption date. As a result of the evaluation performed to date, we have determined that the timing and/or amount of revenue that Sunoco LP recognizes on certain contracts will be impacted by the adoption of the new standard; however, we are quantifying these impacts and cannot currently conclude whether or not they would be material to the financial statements.
We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.
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. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-09
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements and related disclosures.
ASU 2016-16
In October 2016, the FASB issued 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. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.
ASU 2016-17
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests

in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.
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 does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. Sunoco LP early adopted ASC No. 2017-04 during its interim goodwill impairment test in the second quarter of 2017. The Partnership plans to apply 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.
2.ACQUISITIONS AND DIVESTURES
Rover Contribution Agreement
In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, 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.  The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.
Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“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, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“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 ETP. 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.Basin.
Sunoco LP Convenience Store SaleAcquisition
On April 6, 2017,May 1, 2023, Sunoco LP entered into a definitive asset purchase agreementcompleted the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for the sale of a portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven$110 million.

Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.
With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the 7-Eleven purchase agreement.
Sunoco LP Real Estate Sale
In January 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 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 will be sold through a sealed-bid sale. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketed by the third-party brokerage firm.
The assets under the asset purchase agreement, the 208 Stripes sites 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:
 September 30, 2017 December 31, 2016
Carrying amount of assets classified as held for sale:   
Cash and cash equivalents$24
 $20
Inventories183
 188
Other current assets91
 83
Property, plant and equipment, net2,132
 2,185
Goodwill1,216
 1,568
Intangible assets, net499
 503
Other non-current assets, net2
 2
Total assets classified as held for sale in the Consolidated Balance Sheet$4,147
 $4,549
    
Carrying amount of liabilities classified as held for sale:   
Other current and non-current liabilities81
 68
Total liabilities classified as held for sale in the Consolidated Balance Sheet$81
 $68

The results of operations associated with discontinued operations are presented in the following table:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
REVENUES$2,312
 $1,970
 $6,580
 $5,474
        
COSTS AND EXPENSES       
Cost of products sold1,927
 1,585
 5,478
 4,445
Operating expenses236
 250
 727
 727
Depreciation, depletion and amortization5
 47
 68
 149
Selling, general and administrative57
 37
 122
 74
Total costs and expenses2,225
 1,919
 6,395
 5,395
OPERATING INCOME87
 51
 185
 79
Interest expense, net13
 7
 22
 22
Other, net38
 1
 367
 4
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)36
 43
 (204) 53
Income tax expense30
 31
 60
 29
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES$6
 $12
 $(264) $24
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE$—
 $—
 $(9) $—
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 $320 million recognized in the three months ended June 30, 2017 and $44 million recognized in the three months ended September 30, 2017.
3.CASH AND CASH EQUIVALENTS
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. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of March 31, 2023 or December 31, 2022.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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The net change in operating assets and liabilities, net of effects of acquisitions, included in cash flows from operating activities is comprised as follows:
Three Months Ended
March 31,
20232022
Accounts receivable$197 $(2,412)
Accounts receivable from related companies(3)(17)
Inventories429 153 
Other current assets188 (119)
Other non-current assets, net(4)45 
Accounts payable(18)1,885 
Accounts payable to related companies(11)7 
Accrued and other current liabilities(13)230 
Other non-current liabilities31 61 
Derivative assets and liabilities, net5 (153)
Net change in operating assets and liabilities, net of effects of acquisitions$801 $(320)
Non-cash investing and financing activities were as follows:
Three Months Ended
March 31,
20232022
Accrued capital expenditures$436 $475 
Lease assets obtained in exchange for new lease liabilities1 56 
Distribution reinvestment23 12 
 Nine Months Ended
September 30,
 2017 2016
NON-CASH INVESTING ACTIVITIES:   
Accrued capital expenditures$1,237
 $1,001
Losses from subsidiary common unit issuances, net(57) (3)
NON-CASH FINANCING ACTIVITIES:   
Contribution of property, plant and equipment from noncontrolling interest$988
 $—

4.INVENTORIES
Inventories consisted of the following:
March 31,
2023		December 31,
2022
Natural gas, NGLs and refined products$1,419 $1,802 
Crude oil184 246 
Spare parts and other444 413 
Total inventories$2,047 $2,461 
 September 30, 2017 December 31, 2016
Natural gas and NGLs$609
 $699
Crude oil696
 683
Refined products413
 483
Other239
 238
Total inventories$1,957
 $2,103
ETP utilizes commodity derivatives to manage price volatility associated with its natural gasSunoco LP’s fuel inventories stored in our Bammel storage facility. Changes in fairare stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As of March 31, 2023 and December 31, 2022, the carrying value of designated hedgedSunoco LP’s fuel inventory are recorded in inventory on ourincluded lower of cost or market reserves of $87 million and $116 million, respectively. For the three months ended March 31, 2023 and 2022, the Partnership’s consolidated balance sheetsincome statements did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the three months ended March 31, 2023 and 2022, the Partnership’s cost of products sold in our consolidated statementsincluded favorable inventory adjustments of operations.$29 million and $120 million, respectively, related to Sunoco LP’s LIFO inventory.
5.FAIR VALUE MEASURES
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2017 were $47.21 billion and $45.21 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.05 billion and $43.80 billion, respectively. The fair value of our consolidated debt obligations is Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.
We have commodity derivatives and interest rate derivatives 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

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consider our options transacted through oura 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 theThe valuation ofmethodologies employed for our interest rate derivatives asdo not necessitate material judgment, and the inputs are observed from actively quoted public markets and therefore are categorized in 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.2. Level 3 inputs are unobservable. During the ninethree months ended September 30, 2017, March 31, 2023, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2017March 31, 2023 and December 31, 20162022 based on inputs used to derive their fair values:
Fair Value Measurements at
March 31, 2023
Fair Value TotalLevel 1Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX$3 $3 $— 
Swing Swaps IFERC4 4 — 
Fixed Swaps/Futures31 31 — 
Forward Physical Contracts6 — 6 
Power:
Forwards45 — 45 
Futures9 9 — 
Options – Calls2 2 — 
NGLs – Forwards/Swaps219 219 — 
Refined Products – Futures1 1 — 
Crude – Forwards/Swaps41 41 — 
Total commodity derivatives361 310 51 
Other non-current assets28 18 10 
Total assets$389 $328 $61 
Liabilities:
Interest rate derivatives$(43)$— $(43)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX(11)(11)— 
Swing Swaps IFERC(2)(2)— 
Fixed Swaps/Futures(2)(2)— 
Forward Physical Contracts(1)— (1)
Power:
Forwards(45)— (45)
Futures(7)(7)— 
Options – Calls(1)(1)— 
NGLs – Forwards/Swaps(205)(205)— 
Refined Products – Futures(16)(16)— 
Crude – Forwards/Swaps(19)(19)— 
Total commodity derivatives(309)(263)(46)
Total liabilities$(352)$(263)$(89)

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  Fair Value Measurements at
September 30, 2017		Fair Value Measurements at
December 31, 2022
Fair Value Total Level 1 Level 2Fair Value TotalLevel 1Level 2
Assets:     Assets:
Commodity derivatives:     Commodity derivatives:
Natural Gas:     Natural Gas:
Basis Swaps IFERC/NYMEX16
 16
 —
Basis Swaps IFERC/NYMEX$60 $60 $— 
Swing Swaps IFERC2
 —
 2
Swing Swaps IFERC75 75 — 
Fixed Swaps/Futures28
 28
 —
Fixed Swaps/Futures113 113 — 
Forward Physical Swaps3
 —
 3
Forward Physical ContractsForward Physical Contracts10 — 10 
Power:     Power:
Forwards11
 —
 11
Forwards52 — 52 
Futures1
 1
 —
Futures3 3 — 
Options — Puts1
 1
 —
Natural Gas Liquids – Forwards/Swaps213
 213
 —
Refined Products — Futures4
 4
 —
Crude – Futures2
 2
 —
NGLs – Forwards/SwapsNGLs – Forwards/Swaps317 317 — 
Refined Products – FuturesRefined Products – Futures20 20 — 
Crude – Forwards/SwapsCrude – Forwards/Swaps38 38 — 
Total commodity derivatives281
 265
 16
Total commodity derivatives688 626 62 
Other non-current assetsOther non-current assets27 18 9 
Total assets$281
 $265
 $16
Total assets$715 $644 $71 
Liabilities:     Liabilities:
Interest rate derivatives$(210) $—
 $(210)Interest rate derivatives$(23)$— $(23)
Commodity derivatives:     Commodity derivatives:
Natural Gas:     Natural Gas:
Basis Swaps IFERC/NYMEX(22) (22) —
Basis Swaps IFERC/NYMEX(25)(25)— 
Swing Swaps IFERC(3) (1) (2)Swing Swaps IFERC(12)(12)— 
Fixed Swaps/Futures(22) (22) —
Fixed Swaps/Futures(4)(4)— 
Forward Physical Swaps(1) —
 (1)
Forward Physical ContractsForward Physical Contracts(2)— (2)
Power:     Power:
Forwards(9) —
 (9)Forwards(51)— (51)
Futures(1) (1) —
Futures(3)(3)— 
Natural Gas Liquids – Forwards/Swaps(261) (261) —
Refined Products — Futures(3) (3) —
Crude — Futures(1) (1) —
NGLs – Forwards/SwapsNGLs – Forwards/Swaps(358)(358)— 
Refined Products – FuturesRefined Products – Futures(59)(59)— 
Crude – Forwards/SwapsCrude – Forwards/Swaps(12)(12)— 
Total commodity derivatives(323) (311) (12)Total commodity derivatives(526)(473)(53)
Total liabilities$(533) $(311) $(222)Total liabilities$(549)$(473)$(76)

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of March 31, 2023 were $44.43 billion and $47.23 billion, respectively. As of December 31, 2022, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.42 billion and $48.26 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs for similar liabilities.

14
   Fair Value Measurements at
December 31, 2016
 Fair Value Total Level 1 Level 2 Level 3
Assets:       
Natural Gas:       
Basis Swaps IFERC/NYMEX14
 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
 —
Total assets$363
 $356
 $7
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids — Forwards/Swaps(273) (273) —
 —
Refined Products — Futures(23) (23) —
 —
Crude - Futures(13) (13) —
 —
Total commodity derivatives(478) (470) (8) —
Total liabilities$(672) $(470) $(201) $(1)
Table of Contents

6.NET INCOME PER LIMITED PARTNERCOMMON UNIT
A reconciliation of income or loss and weighted average units used in computing basic and diluted income per common unit is as follows:
Three Months Ended
March 31,
20232022
Net income$1,447 $1,487 
Less: Net income attributable to noncontrolling interests321 205 
Less: Net income attributable to redeemable noncontrolling interests13 13 
Net income, net of noncontrolling interests1,113 1,269 
Less: General Partner’s interest in net income1 1 
Less: Preferred Unitholders’ interest in net income109 106 
Common Unitholders’ interest in net income$1,003 $1,162 
Basic Income per Common Unit:
Weighted average common units3,095.5 3,083.5 
Basic income per common unit$0.32 $0.38 
Diluted Income per Common Unit:
Common Unitholders’ interest in net income$1,003 $1,162 
Dilutive effect of equity-based compensation of subsidiaries (1)
— 1 
Diluted income attributable to Common Unitholders$1,003 $1,161 
Weighted average common units3,095.5 3,083.5 
Dilutive effect of unvested restricted unit awards (1)
19.9 17.0 
Weighted average common units, assuming dilutive effect of unvested restricted unit awards3,115.4 3,100.5 
Diluted income per common unit$0.32 $0.37 
(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Income from continuing operations$798
 $29
 $1,475
 $777
Less: Income (loss) from continuing operations attributable to noncontrolling interest546
 (180) 763
 15
Income from continuing operations, net of noncontrolling interest252
 209
 712
 762
Less: General Partner’s interest in income1
 —
 2
 2
Less: Convertible Unitholders’ interest in income11
 2
 25
 3
Income from continuing operations available to Limited Partners$240
 $207
 $685
 $757
Basic Income from Continuing Operations per Limited Partner Unit:       
Weighted average limited partner units1,079.1
 1,045.5
 1,077.9
 1,045.0
Basic income from continuing operations per Limited Partner unit$0.22
 $0.20
 $0.64
 $0.72
Basic loss from discontinued operations per Limited Partner unit$0.00
 $0.00
 $(0.01) $0.00
Diluted Income from Continuing Operations per Limited Partner Unit:       
Income from continuing operations available to Limited Partners$240
 $207
 $685
 $757
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders10
 2
 25
 3
Diluted income from continuing operations available to Limited Partners$250
 $209
 $710
 $760
Weighted average limited partner units1,079.1
 1,045.5
 1,077.9
 1,045.0
Dilutive effect of unconverted unit awards and Convertible Units69.2
 55.2
 69.4
 26.3
Diluted weighted average limited partner units1,148.3
 1,100.7
 1,147.3
 1,071.3
Diluted income from continuing operations per Limited Partner unit$0.22
 $0.19
 $0.62
 $0.71
Diluted loss from discontinued operations per Limited Partner unit$0.00
 $0.00
 $(0.01) $0.00
7.DEBT OBLIGATIONS
Parent Company IndebtednessSenior Notes
The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by allIn the first quarter of 2023, the Partnership redeemed $350 million aggregate principal amount of its and certain3.45% Senior Notes due January 2023, $800 million aggregate principal amount of its subsidiaries’ tangible and intangible assets.
Energy Transfer Equity, L.P.3.60% Senior Notes Offering 
In October 2017, ETE issued $1due February 2023 and $1.00 billion aggregate principal amount of its 4.25% senior notesSenior Notes due 2023. The $990 million netMarch 2023 using proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facilityits Five-Year Credit Facility (defined below).
Credit Facilities and for general partnership purposes.Commercial Paper

The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.
ETE 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.
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 ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, 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 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.
RevolvingFive-Year Credit Facility
On March 24, 2017, the Parent Company entered into aThe Partnership’s revolving credit facility (the “Five-Year Credit Agreement (the “Revolver Credit Agreement”Facility”) 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 Revolver Lenders have committed to provide advancesunsecured borrowings up to an aggregate principal amount of $1.5 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 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 September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.

Subsidiary Indebtedness
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 September 30, 2017, the balance on the term loan was $1.24 billion.
ETP Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500 million aggregate principal amount of ETLP’s 6.50% senior notes due July 2021 and all of the outstanding $700 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.
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 (described below) and for general partnership purposes.
The senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal is payable upon maturity. Interest on the senior notes is paid semi-annually. The senior notes are guaranteed by ETP on a senior unsecured basis as long as it guarantees any of Sunoco Logistics Partners Operations L.P.’s other long-term debt. As a result of the parent guarantee, the senior notes will rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any subordinated debt ETP may incur.  
ETLP Credit Facility
The ETLP Credit Facility allows for borrowings of up to $3.75$5.00 billion and matures in November 2019.April 2027. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of which was commercial paper.
Sunoco Logistics Credit Facilities
ETP maintains the Sunoco Logistics $2.50 billion unsecured revolving credit facility (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco LogisticsFive-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $3.25$7.00 billion under certain conditions.
As of September 30, 2017,March 31, 2023, the Sunoco LogisticsFive-Year Credit Facility had $35 million$1.96 billion of outstanding borrowings.
In December 2016, Sunoco Logistics entered into an agreementborrowings, of which $757 million consisted of commercial paper. The amount available for a 364-day maturityfuture borrowings was $3.01 billion, after accounting for outstanding letters of credit facility (“364-Day Credit Facility”), due to maturein the amount of $32 million. The weighted average interest rate on the earliertotal amount outstanding as of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit FacilityMarch 31, 2023 was terminated and repaid in May 2017.6.05%.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amountAs 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 ofMarch 31, 2023, 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 September 30, 2017, the Sunoco LP credit facility had $644$800 million of outstanding borrowings and $9$7 million in standby letters of credit.credit and matures in April 2027. The unused availabilityamount available for future borrowings at March 31, 2023 was $693 million. The weighted average interest rate on the revolver at September 30, 2017total amount outstanding as of March 31, 2023 was $847 million.6.61%.


On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Agreement with the lenders party thereto and Bank15
Table of America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.Contents
BakkenUSAC Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financingAs of the Bakken Pipeline. The $2.50 billionMarch 31, 2023, USAC’s credit facility, provides substantially allwhich matures in December 2026, had $709 million of the remaining capital necessary to complete the projects.outstanding borrowings and no outstanding letters of credit. As of September 30, 2017, $2.50 billionMarch 31, 2023, USAC had $891 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $375 million. The weighted average interest rate on the total amount outstanding as of March 31, 2023 was outstanding under this credit facility.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”)7.38%. In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.
Compliance with Ourour Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our respective creditdebt agreements as of September 30, 2017.March 31, 2023. For the quarter ended March 31, 2023, our leverage ratio, as calculated pursuant to the covenant related to our revolving credit facility, was 3.26x.
8.PREFERRED UNITSREDEEMABLE NONCONTROLLING INTERESTS
In January 2017, Certain redeemable noncontrolling interests in the Partnership’s subsidiaries were reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of March 31, 2023 and December 31, 2022 included a balance of $477 million related to the USAC Series A preferred units. Redeemable noncontrolling interests also included a balance of $17 million as of March 31, 2023 and $16 million as of December 31, 2022 related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.
9.EQUITY
Energy Transfer Partners, L.P. repurchased all of its 1.9 million outstanding PreferredCommon Units for cash
Changes in the aggregate amount of $53 million.
9. EQUITY
ETE
The changes in ETEEnergy Transfer common units and Convertible Units during the ninethree months ended September 30,2017March 31, 2023 were as follows:
Number of Units
Number of common units at December 31, 20223,094.4 
Common units issued under the distribution reinvestment plan1.8 
Common units vested under equity incentive plans and other0.5 
Number of common units at March 31, 20233,096.7 
 Number of Convertible Units Number of Common Units
Outstanding at December 31, 2016329.3
 1,046.9
Issuance of common units—
 32.2
Outstanding at September 30, 2017329.3
 1,079.1
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 nine months endedSeptember 30, 2017.
Series A Convertible Preferred Units
As of September 30, 2017, the Partnership had 329.3 million Series A Convertible Preferred Units outstanding with a carrying value of $377 million.
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 Repurchase Program
During the ninethree months ended September 30, 2017, ETEMarch 31, 2023, Energy Transfer did not repurchase any ETEof its common units under its current buyback program. As of September 30, 2017, $936March 31, 2023, $880 million remained available to repurchase under the current program.

Energy Transfer Distribution Reinvestment Program
Subsidiary Equity Transactions
The Parent Company accounts forDuring the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the ninethree months ended September 30, 2017, we recognized decreases in partners’ capital of $57 million.
ETP Common Unit Transaction
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 nine months ended September 30, 2017, ETP received proceeds of $498 million, net of $5 million of commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes.
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 nine months ended September 30, 2017,March 31, 2023, distributions of $106$23 million were reinvested under the distribution reinvestment plan.
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.
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 Marathon Petroleum Corporation 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. In July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
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.
Sunoco LP Common Unit Transactions
During the nine months ended September 30, 2017, Sunoco LP received net proceeds of $33 million from the issuance of 1.3 million Sunoco LP common units pursuant to its equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes.program. As of September 30, 2017, $295March 31, 2023, a total of 10 million of Sunoco LP’sEnergy Transfer common units remained available to be issued under the equityexisting registration statement in connection with the distribution agreement.reinvestment program.
Sunoco LPCash Distributions on Energy Transfer Common Units
Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2022 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2022February 7, 2023February 21, 2023$0.3050 
March 31, 2023May 8, 2023May 22, 20230.3075 
Energy Transfer Preferred Units
As of March 31, 2023 and December 31, 2022, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000Series B Preferred Units, 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.
On March 30, 2017,

16
Table of Contents
The following table summarizes changes in the Partnership purchased Sunoco LP’s 12.0 million seriesEnergy Transfer Preferred Units:
Preferred Unitholders
Series ASeries BSeries CSeries DSeries ESeries FSeries GSeries HTotal
Balance, December 31, 2022$958 $556 $440 $434 $786 $496 $1,488 $893 $6,051 
Distributions to partners(30)(18)(8)(9)(15)— — — (80)
Net income18 9 8 9 15 8 27 15 109 
Balance, March 31, 2023$946 $547 $440 $434 $786 $504 $1,515 $908 $6,080 
Preferred Unitholders
Series ASeries BSeries CSeries DSeries ESeries FSeries GSeries HTotal
Balance, December 31, 2021$958 $556 $440 $434 $786 $496 $1,488 $893 $6,051 
Distributions to partners(30)(18)(8)(9)(15)— — — (80)
Net income15 9 8 9 15 8 27 15 106 
Balance, March 31, 2022$943 $547 $440 $434 $786 $504 $1,515 $908 $6,077 
Cash Distributions on Energy Transfer Preferred Units
Distributions declared on the Energy Transfer Preferred Units 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)
December 31, 2022February 1, 2023February 15, 2023$31.250 $33.125 $0.4609 $0.4766 $0.475 $— $— $— 
March 31, 2023May 1, 2023May 15, 202321.982 — 0.4609 0.4766 0.475 33.750 35.625 32.500 
(1)Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis. See additional information on Series A preferred units representing limited partnerdistributions below.
Distributions on the Series A Preferred Units previously accrued at a fixed rate of 6.250% per annum of the liquidation preference of $1,000. Beginning February 15, 2023, the Series A Preferred Units have a floating distribution rate set each quarterly distribution period at a percentage of the $1,000 liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.028% per annum. Distributions on Series A Preferred Units were previously payable semi-annually in arrears until February 15, 2023, and, after February 15, 2023, quarterly in arrears, when, as, and if declared by our General Partner out of legally available funds for such purpose.
Noncontrolling Interests
The Partnership’s consolidated financial statements also include noncontrolling interests in Sunoco LP in a private placement transaction for an aggregate purchase priceand USAC, both of $300 million.which are master limited partnerships, as well as other non-wholly-owned consolidated joint ventures. The distribution rate offollowing sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP Series A Preferred Units is 10.00%, per annum,and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand (less appropriate reserves determined by the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rateboards of 8.00% plus three-month LIBORdirectors of the liquidation preference.

Parent Company Quarterly Distributions of Available Cash
Following are distributions declared and/or paid by ustheir respective general partners) subsequent to December 31, 2016:
Quarter Ended Record Date Payment Date Rate
December 31, 2016 (1) February 7, 2017 February 21, 2017 $0.2850
March 31, 2017 (1) May 10, 2017 May 19, 2017 0.2850
June 30, 2017 (1)
 August 7, 2017 August 21, 2017 $0.2850
September 30, 2017 (1)
 November 7, 2017 November 20, 2017 0.2950
(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.
Our distributions declared with respect to our Convertible Units subsequent to December 31, 2016 were as follows:
Quarter Ended          Record Date Payment Date  Rate
December 31, 2016 February 7, 2017 February 21, 2017 $0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
ETP Quarterly Distributions of Available Cash
Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prior to the Sunoco Logistics Merger. Under the 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 general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” 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.
For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.
Following are distributions declared and/or paid by ETP subsequent to the Sunoco Logistics Merger:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 15, 2017 $0.5350
June 30, 2017 August 7, 2017 August 14, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650

ETE has agreed to relinquish its right to the following amounts of incentive distributions from ETP in future periods:
  Total Year
2017 (remainder) $173
2018 153
2019 128
Each year beyond 2019 33
quarter.
Sunoco LP QuarterlyCash Distributions of Available Cash
Following are distributionsDistributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2016:2022 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2022February 7, 2023February 21, 2023$0.8255 
March 31, 2023May 8, 2023May 22, 20230.8420 

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Quarter Ended Record Date Payment Date Rate
December 31, 2016 February 13, 2017 February 21, 2017 $0.8255
March 31, 2017 May 9, 2017 May 16, 2017 0.8255
June 30, 2017 August 7, 2017 August 15, 2017 0.8255
September 30, 2017 November 7, 2017 November 14, 2017 0.8255
USAC Cash Distributions
Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2022 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2022January 23, 2023February 3, 2023$0.525 
March 31, 2023April 24, 2023May 5, 20230.525 
USAC’s Warrants
As of March 31, 2023 and December 31, 2022, USAC warrants with the right to purchase 10,000,000 USAC common units at a strike price of $19.59 per unit were outstanding and may be exercised by the holders at any time before April 2, 2028.
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
March 31,
2023		December 31,
2022
Available-for-sale securities$10 $9 
Foreign currency translation adjustment(4)1 
Actuarial loss related to pensions and other postretirement benefits(6)(7)
Investments in unconsolidated affiliates, net13 13 
Total AOCI included in partners’ capital, net of tax$13 $16 
 September 30, 2017 December 31, 2016
Available-for-sale securities$7
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain related to pensions and other postretirement benefits9
 7
Investments in unconsolidated affiliates, net3
 4
Subtotal14
 8
Amounts attributable to noncontrolling interest(14) (8)
Total AOCI, net of tax$—
 $—
10.INCOME TAXES
For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the periods presented. The remainder of the increase in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. For the three and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.
11. 10.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
Contingent Residual Support AgreementFERC Proceedings
Rover – AmeriGasFERC - Stoneman House
In connectionlate 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 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. The hearing was set to commence on March 6, 2023; as explained below, this FERC proceeding has been stayed.
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. On April 14, 2023, the United States Supreme Court held against the government in both cases, finding that the district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded to the district courts for further proceedings. Energy Transfer and Rover intend to vigorously defend this claim.
Rover – FERC - Tuscarawas
In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the closinginvestigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the contributionFERC 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 its propane operations in January 2012, ETLP (formerlyProposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer Partners, L.P.)to show cause why they should

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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 contingent residual supportan assessment of $1.55 billionthe potential outcome or range of intercompany borrowings madepotential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by AmeriGasEnforcement Staff and certainintends 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 Natural Gas Act 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 Natural Gas Act. 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 affiliatesbrief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding, which was denied by operation of law as of February 17, 2023. Panhandle submitted requisite compliance filings with maturities throughFERC, but on December 16, 2022, from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notesthe FERC issued by this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reductionorder on Panhandle’s rate case. On January 17, 2023, Panhandle filed its request for rehearing in the amount supportedproceeding, which was denied by ETLP underoperation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed the contingent residual support agreement. Ininitial decision (and the February 2017, AmeriGas repurchased17, 2023 Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration) to the United States Court of Appeals for the District of Columbia (“Court of Appeals”). On April 25, 2023, the Court of Appeals stayed the appeal while FERC further considers its December 16, 2022 order.
On July 1, 2022, Transwestern filed a portionrate case pursuant to Section 4 of its 7.00% senior notes. The remaining outstanding 7.00% senior notes were repurchasedthe Natural Gas Act. By order dated September 9, 2022, a procedural schedule was adopted in May 2017,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 ETLP no longer provides contingent residual supporta Stipulation and Agreement was filed at FERC on April 5, 2023.
On December 1, 2022, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. By order dated February 22, 2023, a procedural schedule was adopted in this proceeding setting the commencement of the hearing for any AmeriGas notes.

FERC AuditOctober 24, 2023, with an initial decision anticipated by March 19, 2024.
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.
Internal Revenue Service Audit
The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service (“IRS”). In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS and most state jurisdictions for 2017 and prior tax years.
Commitments
In the normal course of our business, we purchase, processEnergy Transfer purchases, processes and sellsells natural gas pursuant to long-term contracts and we enterenters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believeEnergy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on ourthe Partnership’s financial position or results of operations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2047.  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:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Rental expense$42
 $31
 $106
 $94
Less: Sublease rental income(6) (6) (19) (18)
Rental expense, net$36
 $25
 $87
 $76
Certain of our subsidiaries’Our joint venture agreements require that theywe fund theirour proportionate sharesshare of capital contributions to theirour unconsolidated affiliates. Such contributions will depend upon theirthe unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

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We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The following table reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:
Three Months Ended
March 31,
20232022
ROW expense$13 $14 
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 March 31, 2023 and December 31, 2022, accruals of approximately $217 million and $200 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 $800 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 following sections 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 in the following sections, 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 U.S.Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) issued permits tothat allowed 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 ofcross the Missouri River at Lake Oahe. After significant delay,Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE also issued easements to allowthat allowed 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 U.S. District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of theRiver. 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 TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the temporary restraining order (“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 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 U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. 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”), 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

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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 District Court vacated the easement and ordered the Dakota Access Pipeline to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the Court of Appeals which had intervened ingranted an administrative stay of the lawsuit inDistrict Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 2016, moved for5, 2020, the Court of Appeals 1) granted a preliminary injunctionstay of the portion of the District Court order that required Dakota Access to shut the pipeline down and TROempty it of oil, 2) denied a motion to blockstay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS, and 3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intended 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.
On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. These motions raised, forOn August 31, 2020, the first time, claims based onUSACE submitted a status report that indicated that it considered the religious rightspresence of the Tribe.pipeline at the Lake Oahe 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 district court denied the TRO and preliminary injunction, and the CRST appealed and requestedTribes subsequently filed a motion seeking an injunction pending appeal into stop 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 have filed related lawsuits to prevent constructionoperation 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 determination 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. Theboth USACE and Dakota Access opposed any shutdown of operationsfiled briefs in opposition of the pipeline during this review process. motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.
On October 11, 2017,January 26, 2021, the Court issuedof Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order allowingvacating the easement. In this same 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 remain in operation duringhear the pendencycase. 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 review process. In early October 2017,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 expects to complete this additional work by April 2018. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relatinghad not changed its position with respect to its remand order.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.
While we believe that theThe pipeline continues to operate pending lawsuits are unlikely to block operationcompletion of the pipeline, we cannot assure this outcome. WeEIS. Energy Transfer anticipates the draft EIS will be completed and published by the USACE in June of 2023, subject to additional delays by the USACE. Energy Transfer cannot determine when or how thesefuture lawsuits will be resolved or the impact they may have on the Bakken Pipeline, which consists of both Dakota Access project.and the Energy Transfer Crude Oil Pipeline; 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 (CMB) 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), along with other refiners, manufacturers and sellers of gasoline,Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBEmethyl tertiary butyl ether (“MTBE”) contamination of groundwater. The plaintiffs, typicallystate-level governmental authorities,entities, assert product liability, claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices.practices

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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 September 30, 2017,March 31, 2023, Sunoco Inc. is a defendantDefendants are defendants in sixtwo cases, including casesone case initiated by the StatesState of New Jersey, Vermont, Pennsylvania, Rhode Island,Maryland and two othersone by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court.
Sunoco, Inc.Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco, and Sunoco Inc. (R&M) have reached a settlement with the State of New Jersey. The court approved the Judicial Consent Order on October 10, 2017.

Partners Marketing & Terminals L.P., 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.
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 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 Merger Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. A hearing on these motions is currently set for January 9, 2018.
The Regency Merger 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 Merger 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 approximately $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 intends to file a petition for review with the Texas Supreme Court.
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 have been voluntarily dismissed. The five remaining lawsuits have been 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 seek rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees.
The ETP-SXL Defendants cannot predict the outcome of the Sunoco Logistics Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing, nor can the ETP-SXL Defendants predict the amount of time and expense that will be required to resolve the Sunoco Logistics Merger Litigation. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Sunoco Logistics Merger.

Litigation Filed By or Against Williams
OnIn April 6,and May 2016, Williams filed a complaint, The Williams Companies, Inc. v.(“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP, LLC, and, 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 partone 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 addedlawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”“Energy Transfer Defendants”). This lawsuit is styled The Williams Companies, Inc. v., alleging that Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCGDefendants breached their obligations under the Energy Transfer-Williams merger agreement (the “Second Delaware Williams Litigation”“Merger Agreement”). In general, Williams allegedalleges 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”), (b) breaching a representationissuing the Partnership’s Series A convertible preferred units (the “Issuance”), and warranty(c) making allegedly untrue representations and warranties 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.Agreement. Williams asked the Court in general, to (a) issue a declaratory judgment that ETE breachedcompel 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 ETEEnergy Transfer Defendants 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 WMB LitigationEnergy Transfer Defendants and issued a declaratory judgment that ETEEnergy Transfer 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 noticenor certain of appeal to the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court of Delawareaffirmed the Court’s ruling on the June 27, 2016 styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.
trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint on September 16, 2016 and soughtseeking 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(the “Termination Fee”) 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.
listed above. Energy Transfer Defendants filed amended counterclaims and affirmative defenses, on September 23, 2016asserting 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. The Energy Transfer Defendants 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 the Energy Defendants’ amended counterclaims and to strike certain of the Energy Transfer Defendants’ affirmative defenses. Following briefingOn December 1, 2017, the Court issued a Memorandum Opinion granting in part and denying in part Williams’ motion to dismiss. The Court dismissed, among other things, the Energy Transfer Defendants’ claim for a $1.48 billion termination fee.
Trial was held on all remaining 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

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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 Ohio 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 partiesfour 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. Briefing on Williams’ motion, the Delaware Court of Chancery held oral argumentsthose motions was completed on November 30, 2016.4, 2022. The parties are awaitingmotions remain pending before the Court’s decision.court.
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.); Barry 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 Charles King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The Barry 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 complaint and added as additional defendants Energy Transfer directors Marshall McCrea and Matthew Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended 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 a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to 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 defendants 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.
On March 23, 2017,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 20(a) of the Delaware Supreme Court affirmedSecurities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of Rover.
On August 10, 2022, the Court appointed the New Mexico State Investment Council and Public Employees Retirement Association of Chancery’s OpinionNew Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and Order onadded as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. On November 7, 2022, the June 2016 trialcourt granted the defendants’ motion to transfer and denied Williams’transferred this action to the United States District Court for the Northern District of Texas. On January 27, 2023, the defendants filed their motion for reargument on April 5, 2017. As a resultto dismiss the New Mexico Funds’ amended complaint.

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DefendantsThe defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or anythese 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 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) 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 Issuance 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 Issuance Defendants believeSupreme Court denied ETMT’s Petition on October 3, 2022. Despite the Issuance Litigationdenial of its Petition for Writ of Certiorari, ETMT is without meritstill vigorously appealing the finality issues underlying the Order and intendhas appealed the denial of the Motion to defend vigorously against itModify to the 10th Circuit in an attempt to get a decision on finality. The appeal to the 10th Circuit has been fully briefed and any other actions challenging the Issuance.oral argument was held on March 21, 2023.
Litigation filed by BP ProductsEnergy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.
On April 30, 2015, BP Products North America Inc.8, 2022, Energy Transfer and ETC Texas Pipeline, Ltd. (“BP”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,”). 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

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$93 million. On April 8, 2022, Plaintiffs filed suit against Culberson, Culberson Equity and Moontower asserting claims for declaratory judgment and breach of contract, contending that they materially breached the Bypass 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 Culberson Equity’s and Moontower’s put notice is void. Culberson, Culberson Equity, and Moontower have answered the lawsuit. Additionally, Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and attorneys’ 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 purchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court in Dallas County, Texas. On April 27, 2022, Culberson filed an application for a temporary restraining order, temporary injunction, and permanent injunction, and Culberson Equity and Moontower joined in that request. 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 and conclusion. Culberson, Culberson Equity and Moontower 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 Moontower Resources Operating, LLC and Moontower Resources WI, LLC as Defendants, and to assert a claim against all Defendants for fraudulent inducement. Trial is currently set for the two-week docket beginning September 26, 2023. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and expense that will 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 FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P.Massachusetts Department of Public Utilities (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”DPU”) 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 Petroleumagainst New England Gas Company (“Marathon”NEG”) and PBF Holdingwith respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company and Toledo Refining Company (collectively, “PBF”(“SUG”). A hearing on the matter was held in November 2016.
On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued her 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 September 30, 2017 and December 31, 2016, accruals of approximately $68 million and $77 million, respectively,NEG assets 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.
In December 2016, Sunoco Logistics received multiple Notice of Violations (“NOVs”) from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016. Sunoco Logistics also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC.  These actions propose penalties in excess of $0.1 million, and ETP is 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, the Partnership does not expect there to be a material impact to its 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 to July, 2017. The Ohio EPA has proposed penalties of approximately $2.3 millionacquired in connection with the alleged violations and is seeking certain corrective actions. ETP is workingmerger transaction with Ohio EPA to resolve the matter. 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 sitesEnergy Transfer in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what ledMarch 2012. Subsequent to the release atmerger, in 2013, SUG sold the Tuscarawas River siteNEG assets to Liberty Utilities (“Liberty,” and what Rover can do to prevent reoccurrence oncetogether with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.
On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.
On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  On August 1, 2017 the EHB lifted the order as to two drill locations.  On August 3, 2017, the EHB lifted the order as to 14 additional locations.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  The EHB Judge encouraged the parties to pursue a settlementcost recoveries with respect to the remaining HDD locationspending complaint before the DPU. Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and facilitatedreconciliation 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 settlement meeting.  On August 7, 2017 a final settlement was reached.  A stipulated order has been submittedlesser (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 EHB Judge with respectenvironmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the settlement.  The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drillsHearing Officer deferred decision on the Mariner East 2 projectmotion to dismiss and approximately 43 drillsissued 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 case remained largely dormant until February 2022, when the Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a procedural schedule on March 16, 2022 (which was amended slightly on August 22, 2022). The parties engaged in discovery and the preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The MA AG served three sets of discovery requests on Respondents on September 9, September 12, and September 20, respectively, to which Respondents timely responded. On October 5, 2022, the MA 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 Stay the Procedural Schedule pending a ruling on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drillsprivilege issue. On October 6, 2022, without even affording Respondents the opportunity to proceed after reevaluation.  Additionally,respond, the settlement agreement requires modificationsDPU granted the MA AG’s request to several ofstay the HDD plans that are part ofprocedural schedule. Accordingly, all previous deadlines (including 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 andMA AG’s October 7, 2022, deadline to submit a corrective action plan for agency reviewdirect pre-filed testimony) are presently stayed. Respondents cannot predict the ultimate outcome of this regulatory proceeding, nor can they predict the amount of time and approval.  SPLP is workingexpense that will be required to fulfillresolve these claims; however, Respondents will vigorously defend themselves against the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.
No amounts have been recorded in our September 30, 2017 or December 31, 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

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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 theour 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.
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.polychlorinated biphenyls (“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.
Currently operating Sunoco, Inc. retail sites previously contributed to Sunoco LP in January 2016.
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 September 30, 2017, Sunoco, Inc.March 31, 2023, the Partnership had been named as a PRP at approximately 4431 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 have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
March 31,
2023		December 31,
2022
Current$49 $54 
Non-current227 228 
Total environmental liabilities$276 $282 

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 September 30, 2017 December 31, 2016
Current$42
 $31
Non-current302
 318
Total environmental liabilities$344
 $349
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 three months ended September 30, 2017March 31, 2023 and 2016,2022, the Partnership recorded $7$8 million and $12$4 million, respectively, of expenditures related to environmental cleanup programs. During
Our pipeline operations are subject to regulation by the nine months ended September 30, 2017 and 2016, the Partnership recorded $22 million and $31 million, respectively.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase AgreementUnited States Department of Transportation under PHMSA, pursuant 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, EPAwhich PHMSA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relateestablished requirements relating to the time period that Sunoco, Inc. operateddesign, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the refinery. Specifically, EPAOffice of Pipeline Safety, has claimed thatpromulgated 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 refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or in conformance with their design,other effective means to assess the integrity of these regulated pipeline segments, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010the regulations require prompt action to address integrity issues raised by the assessment and 2011 to the EPA that failed to includeanalysis. Integrity testing and assessment of all of these assets will continue, and the information required bypotential 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 regulations. EPA has proposed penalties in excesscontinued safe and reliable operation of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannotour pipelines; however, no estimate can be reasonably determinedmade 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 likely range of such expenditures.
Our operations are also subject to the requirements of OSHA,the Federal Occupational Safety and Health Act (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’sthe 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.

11.REVENUE
Disaggregation of Revenue
The Partnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 13 depicts the disaggregation of revenue by segment.
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 allow 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:
Contract Liabilities
Balance, December 31, 2022$615 
Additions278 
Revenue recognized(301)
Balance, March 31, 2023$592 
Balance, December 31, 2021$459 
Additions266 
Revenue recognized(209)
Other(10)
Balance, March 31, 2022$506 
The balances of Sunoco LP’s contract assets were as follows:
March 31,
2023		December 31,
2022
Contract balances:
Contract assets$222 $200 
Accounts receivable from contracts with customers528 834 
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 contacts, only the fixed components of the contracts are included in the following table.
As of March 31, 2023, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $39.06 billion. The Partnership expects to recognize this amount as revenue within the time bands illustrated in the following table:
Years Ending December 31,
2023
(remainder)20242025ThereafterTotal
Revenue expected to be recognized on contracts with customers existing as of March 31, 2023$5,495 $6,360 $5,429 $21,775 $39,059 
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, our subsidiarieswe utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
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

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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 ETP’sour intrastate transportation and storage segment and operational gas sales on ETP’sin 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 ETP’sour midstream segment whereby itsour subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We use derivatives in ETP’s NGL and refined products transportation and services segment to manage our storage facilities and the purchase and sale of purity 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.NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment.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 ETP’sour 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 ETP’sour 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 ETP’sour 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.


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The following table details our outstanding commodity-related derivatives:
March 31, 2023December 31, 2022
Notional VolumeMaturityNotional VolumeMaturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures215 2023-2024145 2023
Basis Swaps IFERC/NYMEX (1)
(49,423)2023(39,563)2023
Power (Megawatt):
Forwards85,400 2023-2029— 2023-2029
Futures(289,918)2023-2024(21,384)2023
Options – Puts8,000 2023-2024119,200 2023
Options – Calls(119,200)2023-2024— —
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX40,533 2023-202442,440 2023-2024
Swing Swaps IFERC(58,778)2023-2024(202,815)2023-2024
Fixed Swaps/Futures(10,225)2023-2025(15,758)2023-2025
Forward Physical Contracts532 2023-20252,423 2023-2024
NGLs (MBbls) – Forwards/Swaps10,341 2023-20256,934 2023-2025
Crude (MBbls) – Forwards/Swaps(4,257)2023-2025795 2023-2024
Refined Products (MBbls) – Futures(2,401)2023-2024(3,547)2023-2024
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX(45,535)2023(37,448)2023
Fixed Swaps/Futures(45,535)2023(37,448)2023
Hedged Item – Inventory45,535 202337,448 2023
 September 30, 2017 December 31, 2016
 Notional Volume Maturity Notional Volume Maturity
Mark-to-Market Derivatives       
(Trading)       
Natural Gas (MMBtu):       
Fixed Swaps/Futures1,297,500
 2017-2018 (682,500) 2017
Basis Swaps IFERC/NYMEX (1)
(15,810,000) 2017-2019 2,242,500
 2017
Options – Puts13,000,000
 2018 —
 —
Power (Megawatt):       
Forwards665,040
 2017-2018 391,880
 2017-2018
Futures(213,840) 2017-2018 109,564
 2017-2018
Options — Puts(280,800) 2017-2018 (50,400) 2017
Options — Calls545,600
 2017-2018 186,400
 2017
Crude (Bbls):       
Futures(160,000) 2017 (617,000) 2017
(Non-Trading)       
Natural Gas (MMBtu):       
Basis Swaps IFERC/NYMEX67,500
 2017-2020 10,750,000
 2017-2018
Swing Swaps IFERC91,897,500
 2017-2019 (5,662,500) 2017
Fixed Swaps/Futures(20,220,000) 2017-2019 (52,652,500) 2017-2019
Forward Physical Contracts(140,937,993) 2017-2018 (22,492,489) 2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps(8,744,200) 2017-2019 (5,786,627) 2017
Refined Products (Bbls) — Futures(1,947,000) 2017-2018 (3,144,000) 2017
Corn (Bushels) — Futures650,000
 2017-2018 1,580,000
 2017
Fair Value Hedging Derivatives       
(Non-Trading)       
Natural Gas (MMBtu):       
Basis Swaps IFERC/NYMEX(41,102,500) 2017 (36,370,000) 2017
Fixed Swaps/Futures(41,102,500) 2017 (36,370,000) 2017
Hedged Item — Inventory41,102,500
 2017 36,370,000
 2017
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
(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
March 31,
2023		December 31,
2022
July 2024(2)
Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate$400 $400 
(1)Floating rates are based on SOFR.
(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.

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    Notional Amount Outstanding
Term 
Type(1)
 September 30, 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
In April 2023, USAC entered into an interest rate swap to manage interest rate risk associated with its floating-rate credit facility. The interest rate swap has a notional amount of $700 million and a mandatory termination in April 2025. Under the interest rate swap, USAC is to pay a fixed interest rate of 3.785% and receive floating interest rate payments that are indexed to SOFR.
(1)
Floating rates are based on 3-month LIBOR.
(2)
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern ETP’sthe Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, ETPthe Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. ETPThe Partnership also implements the use ofuses industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, ETP utilizeswe utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
ETP’sOur 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, oilindustrial end-users, municipalities, gas and gas producers, motor fuel distributors, municipalities,electric utilities, midstream companies and midstream companies. ETP’sindependent power generators. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact itsour counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
ETPThe Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily 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 ETPus on or about the settlement date for non-exchange traded derivatives, and ETP exchangeswe exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
Fair Value of Derivative Instruments
Asset DerivativesLiability Derivatives
March 31,
2023		December 31,
2022		March 31,
2023		December 31,
2022
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)$47 $87 $(21)$(7)
47 87 (21)(7)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)255 506 (231)(411)
Commodity derivatives59 95 (57)(108)
Interest rate derivatives— — (43)(23)
314 601 (331)(542)
Total derivatives$361 $688 $(352)$(549)

31
 Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives
 September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016
Derivatives designated as hedging instruments:       
Commodity derivatives (margin deposits)$7
 $—
 $—
 $(4)
Derivatives not designated as hedging instruments:       
Commodity derivatives (margin deposits)$222
 $338
 $(262) $(416)
Commodity derivatives52
 25
 (61) (58)
Interest rate derivatives—
 —
 (210) (193)
Embedded derivatives in the ETP Preferred Units—
 —
 —
 (1)
 274
 363
 (533) (668)
Total derivatives$281
 $363
 $(533) $(672)
Table of Contents
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 September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016Balance Sheet LocationMarch 31,
2023		December 31,
2022		March 31,
2023		December 31,
2022
Derivatives without offsetting agreements Derivative assets (liabilities) $—
 $—
 $(210) $(194)Derivatives without offsetting agreementsDerivative liabilities$— $— $(43)$(23)
Derivatives in offsetting agreements:Derivatives in offsetting agreements:        Derivatives in offsetting agreements:
OTC contracts Derivative assets (liabilities) 52
 25
 (61) (58)OTC contractsDerivative assets (liabilities)59 95 (57)(108)
Broker cleared derivative contracts Other current assets 229
 338
 (262) (420)Broker cleared derivative contractsOther current assets (liabilities)302 593 (252)(418)
Total gross derivativesTotal gross derivatives 281
 363
 (533) (672)Total gross derivatives361 688 (352)(549)
Less offsetting agreements:        
Offsetting agreements:Offsetting agreements:
Counterparty netting Derivative assets (liabilities) (10) (4) 10
 4
Counterparty nettingDerivative assets (liabilities)(53)(85)53 85 
Payments on margin deposit Other current assets (220) (338) 220
 338
Counterparty nettingCounterparty nettingOther current assets (liabilities)(208)(359)208 359 
Total net derivativesTotal net derivatives $51
 $21
 $(303) $(330)Total net derivatives$100 $244 $(91)$(105)
We disclose the non-exchange traded financial derivative instruments as price risk managementderivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarizetable summarizes the location and amounts recognized in our consolidated statements of operations with respect to our derivative financial instruments:
LocationAmount of Gain (Loss) Recognized in Income on Derivatives
Three Months Ended
March 31,
20232022
Derivatives not designated as hedging instruments:
Commodity derivatives – TradingCost of products sold$(12)$17 
Commodity derivatives – Non-tradingCost of products sold68 (17)
Interest rate derivativesGains (losses) on interest rate derivatives(20)114 
Total$36 $114 
  
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
   Three Months Ended
September 30,		 Nine Months Ended
September 30,
    2017 2016 2017 2016
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivatives Cost of products sold $2
 $(9) $4
 $8
Total   $2
 $(9) $4
 $8
  
Location of Gain/(Loss)
Recognized in Income
on Derivatives
 Amount of Gain/(Loss) Recognized in Income on Derivatives
   Three Months Ended
September 30,		 Nine Months Ended
September 30,
    2017 2016 2017 2016
Derivatives not designated as hedging instruments:        
Commodity derivatives —Trading Cost of products sold $(5) $(7) $21
 $(24)
Commodity derivatives —Non-trading Cost of products sold (25) (16) (6) (61)
Interest rate derivatives Losses on interest rate derivatives (8) (28) (28) (179)
Embedded derivatives Other, net —
 8
 1
 4
Total   $(38) $(43) $(12) $(260)
13.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 9.
ETP previously had agreements with the Parent Company to provide services on its behalf and the behalf of other subsidiaries of the Parent Company, which included the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. These agreements expired in 2016.
In addition, ETE recorded sales with affiliates of $105 million and $49 million during the three months ended September 30, 2017 and 2016, respectively, and $201 million and $175 million during the nine months ended September 30, 2017 and 2016, respectively.
14.    REPORTABLE SEGMENTS
Our financial statementsreportable segments, which conduct their business primarily in the United States, are as follows:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
•NGL and refined products transportation and services;
•crude oil transportation and services;
•investment in Sunoco LP;
•investment in USAC; and
•all other.

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Consolidated revenues and expenses reflect the following reportable business segments:elimination of all material intercompany transactions.
InvestmentRevenues from our intrastate transportation and storage segment are primarily reflected in ETP, including the consolidated operations of ETP;
Investmentnatural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in Sunoco LP, including the consolidated operations of Sunoco LP;
Investmentgathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in Lake Charles LNG, including the operations of Lake Charles LNG;natural gas sales, NGL sales and
Corporate gathering, transportation and Other, including the following:
activities of the Parent Company;other fees. Revenues from our NGL and

the goodwill refined products transportation and property, plantservices segment are primarily reflected in NGL sales and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
The Investmentgathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment reflects the resultsare primarily reflected in refined 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 natural gas sales and gathering, transportation and other fees.
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of Sunoco LP and the legacy Sunoco, Inc. retail business for the periods presented.
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 gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair valueInventory adjustments (excludingthat are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market adjustments). reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA reflectsand consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the Partnership’s proportionate ownershipsame 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 for less than wholly owned subsidiaries based on 100%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 subsidiaries’ resultsearnings or cash flows of operations.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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Table of Contents
The following tables present financial information by segment:
Three Months Ended
March 31,
20232022
Revenues:
Intrastate transportation and storage:
Revenues from external customers$814 $1,475 
Intersegment revenues476 157 
1,290 1,632 
Interstate transportation and storage:
Revenues from external customers622 547 
Intersegment revenues12 19 
634 566 
Midstream:
Revenues from external customers809 1,131 
Intersegment revenues1,945 2,794 
2,754 3,925 
NGL and refined products transportation and services:
Revenues from external customers4,737 5,245 
Intersegment revenues866 1,032 
5,603 6,277 
Crude oil transportation and services:
Revenues from external customers6,079 5,926 
Intersegment revenues1 — 
6,080 5,926 
Investment in Sunoco LP:
Revenues from external customers5,349 5,397 
Intersegment revenues13 5 
5,362 5,402 
Investment in USAC:
Revenues from external customers192 159 
Intersegment revenues5 4 
197 163 
All other:
Revenues from external customers393 611 
Intersegment revenues151 104 
544 715 
Eliminations(3,469)(4,115)
Total revenues$18,995 $20,491 

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Table of Contents
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Segment Adjusted EBITDA:       
Investment in ETP$1,744
 $1,390
 $4,757
 $4,172
Investment in Sunoco LP199
 189
 574
 512
Investment in Lake Charles LNG43
 45
 131
 133
Corporate and Other(3) (37) (25) (142)
Adjustments and Eliminations(74) (83) (211) (208)
Total1,909
 1,504
 5,226
 4,467
Depreciation, depletion and amortization(632) (548) (1,840) (1,596)
Interest expense, net(505) (474) (1,471) (1,336)
Losses on interest rate derivatives(8) (28) (28) (179)
Non-cash unit-based compensation expense(29) (23) (76) (46)
Unrealized gains (losses) on commodity risk management activities(76) (21) 22
 (105)
Losses on extinguishments of debt—
 —
 (25) —
Inventory valuation adjustments141
 35
 38
 203
Equity in earnings of unconsolidated affiliates92
 49
 228
 205
Adjusted EBITDA related to unconsolidated affiliates(205) (157) (554) (503)
Adjusted EBITDA related to discontinued operations(92) (93) (253) (220)
Impairment of investment in an unconsolidated affiliate—
 (308) —
 (308)
Other, net46
 4
 111
 44
Income (loss) before income tax benefit$641
 $(60) $1,378
 $626
Three Months Ended
March 31,
20232022
Segment Adjusted EBITDA:
Intrastate transportation and storage$409 $444 
Interstate transportation and storage536 453 
Midstream641 807 
NGL and refined products transportation and services939 700 
Crude oil transportation and services526 593 
Investment in Sunoco LP221 191 
Investment in USAC118 98 
All other43 54 
Adjusted EBITDA (consolidated)$3,433 $3,340 

Three Months Ended
March 31,
20232022
Reconciliation of net income to Adjusted EBITDA:
Net income$1,447 $1,487 
Depreciation, depletion and amortization1,059 1,028 
Interest expense, net of interest capitalized619 559 
Income tax expense (benefit)71 (9)
Impairment losses1 300 
(Gains) losses on interest rate derivatives20 (114)
Non-cash compensation expense37 36 
Unrealized losses on commodity risk management activities130 45 
Inventory valuation adjustments (Sunoco LP)(29)(120)
Adjusted EBITDA related to unconsolidated affiliates161 125 
Equity in earnings of unconsolidated affiliates(88)(56)
Other, net5 59 
Adjusted EBITDA (consolidated)$3,433 $3,340 

35
 September 30, 2017 December 31, 2016
Assets:   
Investment in ETP$77,011
 $70,191
Investment in Sunoco LP8,307
 8,701
Investment in Lake Charles LNG1,611
 1,508
Corporate and Other620
 711
Adjustments and Eliminations(2,169) (2,100)
Total assets$85,380
 $79,011
Table of Contents
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Revenues:       
Investment in ETP:       
Revenues from external customers$6,876
 $5,488
 $20,168
 $15,167
Intersegment revenues97
 43
 276
 134
 6,973
 5,531
 20,444
 15,301
Investment in Sunoco LP:       
Revenues from external customers2,549
 2,167
 7,321
 5,912
Intersegment revenues6
 —
 9
 6
 2,555
 2,167
 7,330
 5,918
Investment in Lake Charles LNG:       
Revenues from external customers49
 50
 148
 148
        
Adjustments and Eliminations(103) (43) (285) (140)
Total revenues$9,474
 $7,705
 $27,637
 $21,227
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP and Lake Charles LNG.
Investment in ETP
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Intrastate Transportation and Storage$729
 $583
 $2,196
 $1,457
Interstate Transportation and Storage220
 231
 652
 714
Midstream665
 582
 1,863
 1,799
NGL and refined products transportation and services1,989
 1,397
 5,874
 4,014
Crude oil transportation and services2,714
 1,856
 7,749
 5,146
All Other656
 882
 2,110
 2,171
Total revenues6,973
 5,531
 20,444
 15,301
Less: Intersegment revenues97
 43
 276
 134
Revenues from external customers$6,876
 $5,488
 $20,168
 $15,167
The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger.


Investment in Sunoco LP
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Retail operations$88
 $80
 $247
 $241
Wholesale operations2,467
 2,087
 7,083
 5,677
Total revenues2,555
 2,167
 7,330
 5,918
Less: Intersegment revenues6
 —
 9
 6
Revenues from external customers$2,549
 $2,167
 $7,321
 $5,912
Investment in Lake Charles LNG
Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling.

15. 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
(unaudited)

 September 30, 2017 December 31, 2016
ASSETS   
Current assets:   
Cash and cash equivalents$—
 $2
Accounts receivable from related companies64
 55
Other current assets2
 —
Total current assets66
 57
Property, plant and equipment, net27
 36
Advances to and investments in unconsolidated affiliates6,031
 5,088
Intangible assets, net—
 1
Goodwill9
 9
Other non-current assets, net17
 10
Total assets$6,150
 $5,201
LIABILITIES AND PARTNERS’ CAPITAL   
Current liabilities:   
Accounts payable$—
 $1
Accounts payable to related companies—
 22
Interest payable79
 66
Accrued and other current liabilities3
 3
Total current liabilities82
 92
Long-term debt, less current maturities6,684
 6,358
Long-term notes payable – related companies574
 443
Other non-current liabilities2
 2
Commitments and contingencies
 
Partners’ capital:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders(1,566) (1,871)
Series A Convertible Preferred Units377
 180
Total partners’ deficit(1,192) (1,694)
Total liabilities and equity$6,150
 $5,201


STATEMENTS OF OPERATIONS
(unaudited)
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)
$(3) $(75) $(25) $(156)
OTHER INCOME (EXPENSE):       
Interest expense, net(88) (81) (257) (244)
Equity in earnings of unconsolidated affiliates343
 367
 1,012
 1,166
Losses on extinguishments of debt—
 —
 (25) —
Other, net—
 (2) (2) (4)
NET INCOME252
 209
 703
 762
General Partner’s interest in net income1
 —
 2
 2
Convertible Unitholders’ interest in income11
 2
 25
 3
Limited Partners’ interest in net income$240
 $207
 $676
 $757

(1)
Prior periods include management fees paid by ETE to ETP, which management fees will no longer be paid subsequent to March 31, 2017.

STATEMENTS OF CASH FLOWS
(unaudited)
 Nine Months Ended
September 30,
 2017 2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$620
 $718
CASH FLOWS FROM INVESTING ACTIVITIES:   
Contributions to unconsolidated affiliate(861) (70)
Capital expenditures(1) (15)
Contributions in aid of construction costs7
 —
Net cash used in investing activities(855) (85)
CASH FLOWS FROM FINANCING ACTIVITIES:   
Proceeds from borrowings2,116
 180
Principal payments on debt(1,795) (155)
Proceeds from affiliate131
 129
Distributions to partners(752) (780)
Units issued for cash568
 —
Debt issuance costs(35) —
Net cash provided by (used in) financing activities233
 (626)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(2) 7
CASH AND CASH EQUIVALENTS, beginning of period2
 1
CASH AND CASH EQUIVALENTS, end of period$—
 $8



ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in Exhibit 99.1 to the Partnership’s Annual Report on Form 8-K10-K for the year ended December 31, 2022 filed with the SEC on October 2, 2017.February 17, 2023. 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 “Part I -– Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016.2022 filed with the SEC on February 17, 2023. Additional information on forward-looking statements is discussed in “Forward-Looking Statements.”
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, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. See Note 1 to the consolidated financial statements for information related to recent name changes of our subsidiaries.
OVERVIEW
At September 30, 2017, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 27.5 million ETP common units, 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries.
Our reportable segments are as follows:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
RECENT DEVELOPMENTS
ETE Senior Notes Offering Lotus Midstream Acquisition
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 are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.
ETE January 2017 Private Placement andOn May 2, 2023, Energy Transfer Partners, L.P. Unit Purchase
In January 2017, ETE issued 32.2acquired Lotus Midstream Operations, LLC (“Lotus Midstream”) for total consideration of $900 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds ofcash and approximately $580 million, which ETE used to purchase 23.744.5 million newly issued Energy Transfer Partners, L.P. common units.
ETP Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500 million aggregate principal amount of ETLP’s 6.50% senior notes due July 2021 Lotus Midstream owns and all of the outstanding $700 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.
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 inoperates Centurion Pipeline Company LLC, 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 July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interestintegrated crude midstream platform located in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, 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.  The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.
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.
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. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 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.Permian Basin.
Sunoco LP Convenience Store SaleAcquisition
On April 6, 2017,May 1, 2023, Sunoco LP entered into a definitive asset purchase agreementcompleted the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for the sale of a portfolio of approximately 1,112$110 million. Sunoco LP operated retail fuel outletsexpects the acquisition to be accretive to its unitholders in 19 geographic regions, together with ancillary businesses 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”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarteryear of 2018.
With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligations related to the divested retail assets.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased Sunoco LP’s 12,000,000 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 will be 10.00%, 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.
Sunoco LP Real Estate Sale
In January 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 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 will be sold through a sealed-bid sale. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketed by the third-party brokerage firm.

Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“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, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“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 ETP. 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 Marathon Petroleum Corporation 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. In July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.ownership.
Quarterly Cash Distribution
In October 2017, ETEApril 2023, Energy Transfer announced itsa quarterly distribution of $0.295$0.3075 per unit ($1.181.23 annualized) on ETEEnergy Transfer common units for the quarter ended March 31, 2023.
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.

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Table of Contents
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 Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline, 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 Florida Gas Transmission Pipeline, 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 Natural Gas Act 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 Natural Gas Act. 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, which was denied by operation of law as of February 17, 2023. Panhandle submitted requisite compliance filings with FERC, but 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, which was denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed the initial decision (and the February 17, 2023 Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration) to the United States Court of Appeals for the District of Columbia (“Court of Appeals”). On April 25, 2023, the Court of Appeals stayed the appeal while FERC further considers its December 16, 2022 order.
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 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.
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 market-based rates. The FERC’s indexing methodology is subject to review every five years.

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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, 2017.2026, 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.
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.
Results
RESULTS OF OPERATIONS
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of Operations
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 gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair valueInventory adjustments (excludingthat are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market adjustments). reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA reflectsand consolidated Adjusted EBITDA reflect amounts for less than wholly owned subsidiariesunconsolidated affiliates based on 100%the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the subsidiaries’ results of operations.

Consolidated Results

 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Segment Adjusted EBITDA:           
Investment in ETP$1,744
 $1,390
 $354
 $4,757
 $4,172
 $585
Investment in Sunoco LP199
 189
 10
 574
 512
 62
Investment in Lake Charles LNG43
 45
 (2) 131
 133
 (2)
Corporate and Other(3) (37) 34
 (25) (142) 117
Adjustments and Eliminations(74) (83) 9
 (211) (208) (3)
Total1,909
 1,504
 405
 5,226
 4,467
 759
Depreciation, depletion and amortization(632) (548) (84) (1,840) (1,596) (244)
Interest expense, net(505) (474) (31) (1,471) (1,336) (135)
Losses on interest rate derivatives(8) (28) 20
 (28) (179) 151
Non-cash unit-based compensation expense(29) (23) (6) (76) (46) (30)
Unrealized gains (losses) on commodity risk management activities(76) (21) (55) 22
 (105) 127
Losses on extinguishments of debt—
 —
 —
 (25) —
 (25)
Inventory valuation adjustments141
 35
 106
 38
 203
 (165)
Equity in earnings of unconsolidated affiliates92
 49
 43
 228
 205
 23
Adjusted EBITDA related to unconsolidated affiliates(205) (157) (48) (554) (503) (51)
Adjusted EBITDA related to discontinued operations(92) (93) 1
 (253) (220) (33)
Impairment of investment in an unconsolidated affiliate—
 (308) 308
 —
 (308) 308
Other, net46
 4
 42
 111
 44
 67
Income (loss) before income tax benefit641
 (60) 701
 1,378
 626
 752
Income tax benefit(157) (89) (68) (97) (151) 54
Income from continuing operations798
 29
 769
 1,475
 777
 698
Income (loss) from discontinued operations, net of income taxes6
 12
 (6) (264) 24
 (288)
Net income$804
 $41
 $763
 $1,211
 $801
 $410
Seesame items with respect to the detailed discussionunconsolidated 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, is analyzed for each segment in the section titled “Segment Operating Results” below.Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and 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.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for

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Consolidated Results
Three Months Ended
March 31,
20232022Change
Segment Adjusted EBITDA:
Intrastate transportation and storage$409 $444 $(35)
Interstate transportation and storage536 453 83 
Midstream641 807 (166)
NGL and refined products transportation and services939 700 239 
Crude oil transportation and services526 593 (67)
Investment in Sunoco LP221 191 30 
Investment in USAC118 98 20 
All other43 54 (11)
Adjusted EBITDA (consolidated)$3,433 $3,340 $93 
Three Months Ended
March 31,
20232022Change
Reconciliation of net income to Adjusted EBITDA:
Net income$1,447 $1,487 $(40)
Depreciation, depletion and amortization1,059 1,028 31 
Interest expense, net of interest capitalized619 559 60 
Income tax expense (benefit)71 (9)80 
Impairment losses1 300 (299)
(Gains) losses on interest rate derivatives20 (114)134 
Non-cash compensation expense37 36 1 
Unrealized losses on commodity risk management activities130 45 85 
Inventory valuation adjustments (Sunoco LP)(29)(120)91 
Adjusted EBITDA related to unconsolidated affiliates161 125 36 
Equity in earnings of unconsolidated affiliates(88)(56)(32)
Other, net5 59 (54)
Adjusted EBITDA (consolidated)$3,433 $3,340 $93 
Net Income. For the three and nine months ended September 30, 2017March 31, 2023 compared to the same period last year, net income decreased $40 million, or approximately 3%. Operating income increased $216 million primarily due to the recognition of a $300 million impairment loss in the prior period, partially offset by increases in operating expenses. In addition, equity in earnings of unconsolidated affiliates increased $32 million. These increases to net income were offset by higher interest expense and losses on interest rate derivatives, as well as an increase in income tax expense. Additional discussion on these items affecting net income is available below and in “Segment Operating Results.”
Adjusted EBITDA (consolidated). For the three months ended March 31, 2023 compared to the same period last year, Adjusted EBITDA increased $93 million, or approximately 3%. This increase included a $239 million increase from the NGL and refined products transportation and services segment, primarily driven by higher volumes, higher rates and optimization activities. The increase in consolidated Adjusted EBITDA also included an $83 million increase from the interstate transportation and storage segment, primarily due to higher contracted volumes, higher rates and new assets placed in service. These increases in Adjusted EBITDA were partially offset by a $166 million decrease from the midstream segment primarily driven by unfavorable natural gas and NGL prices, as well as a $67 million decrease from the crude oil transportation and services segment primarily driven by lower results from our crude oil acquisition and marketing business.
Additional information on changes impacting Adjusted EBITDA for the three months ended March 31, 2023 compared to the same period last year is available in “Segment Operating Results.”

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Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three months ended March 31, 2023 compared to the same period last year primarily due to additional depreciation and amortization from assets recently placed in service.service and recent acquisitions.
Interest Expense, Net.net of interest capitalized. Interest expense, net of interest capitalized, increased for the three and nine months ended September 30, 2017 increasedMarch 31, 2023 compared to the same period last year, primarily due to the following:
increase of $4 million of expense recognized by•the Partnership’s (excluding Sunoco LP for the three months ended September 30, 2017 comparedand USAC) interest expense increased by $40 million due to the same period in the prior yearhigher interest rates on floating rate debt and lower capitalized interest, partially offset by a lower aggregate debt balance;
•Sunoco LP’s interest expense increased by $12 million primarily due to higher interest rates on Sunoco LP’sfloating rate debt; and
•USAC’s interest expense increased by $8 million primarily due to higher weighted average interest rates and increased borrowings under its revolving credit facility that Sunoco LP entered into in September 2014 and an increase of $51 million of expense foragreement.
Income Tax Expense (Benefit). For the ninethree months ended September 30, 2017March 31, 2023 compared to the same period in the priorlast year, income tax expense increased due to higher earnings from the issuancePartnership's consolidated corporate subsidiaries.
Impairment Losses. The $300 million impairment loss during the three months ended March 31, 2022 was related to the impairment of Sunoco LP’sEnergy Transfer Canada’s assets recorded in March 2022, based on the anticipated proceeds from the expected sale of those assets. The sale was completed in August 2022.

$800For the three months ended March 31, 2023, impairment losses included a total of $1 million 6.250% senior notes on April 7, 2016, as well as the increase in borrowings under Sunoco LP’s revolving credit facility; and
increases of $22 million and $71 million, respectively, of expense recognized by ETP primarily attributableUSAC related to increases in long-term debt, including the Dakota Access and ETCO term loans that became effective in August 2016.its compression equipment.
(Gains) Losses on Interest Rate Derivatives.Losses Gains and losses on interest rate derivatives during the three and nine months ended September 30, 2017 and 2016 resulted from decreaseschanges in forward interest rates.rates, which caused our forward-starting swaps to change in value. The magnitude of the gains and losses during the respective periods also reflected higher aggregate notional amount of interest rate swaps outstanding in the prior period.
Unrealized Gains (Losses)Losses on Commodity Risk Management Activities. SeeThe unrealized losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results,” and additional information on the unrealized gains (losses) on commodity risk management activitiescommodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and in Note 12 to our consolidated financial statements included in the segment results below.“Item 1. Financial Statements.”
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded duringrepresent changes in lower of cost or market reserves 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 at the end of the period. For the three and nine months ended September 30, 2017March 31, 2023 and 2016, for the inventory associated with ETP’s crude oil transportation2022, increases in fuel prices reduced lower of cost or market reserve requirements by $29 million and service and ETP’s NGL and refined products transportation and services inventories as a result of commodity price changes during the respective periods.$120 million, respectively, resulting in favorable impacts to net income.
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.Operating Results.”
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. Includes Other, net primarily includes the amortization of regulatory assets and other income and expense amounts.
Income Tax (Expense) Benefit. For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact

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Table of a one-time adjustmentContents
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the periods presented. The remainderunconsolidated affiliates:
Three Months Ended
March 31,
20232022Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus$34 $34 $— 
MEP25 (4)29 
White Cliffs1 — 1 
Explorer8 4 4 
Other20 22 (2)
Total equity in earnings of unconsolidated affiliates$88 $56 $32 
Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus$79 $77 $2 
MEP34 5 29 
White Cliffs6 5 1 
Explorer13 7 6 
Other29 31 (2)
Total Adjusted EBITDA related to unconsolidated affiliates$161 $125 $36 
Distributions received from unconsolidated affiliates:
Citrus$48 $60 $(12)
MEP33 4 29 
White Cliffs5 5 — 
Explorer8 5 3 
Other23 16 7 
Total distributions received from unconsolidated affiliates$117 $90 $27 
(1)These amounts represent our proportionate share of the increaseAdjusted EBITDA of our unconsolidated affiliates and are based on our equity in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition,earnings or losses of our unconsolidated affiliates adjusted for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for oneour proportionate share of the subsidiaries. For the threeunconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.taxes.
Segment Operating Results
Investment in ETP
 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Revenues$6,973
 $5,531
 $1,442
 $20,444
 $15,301
 $5,143
Cost of products sold4,876
 3,844
 1,032
 14,582
 10,280
 4,302
Unrealized (gains) losses on commodity risk management activities81
 15
 66
 (17) 96
 (113)
Operating expenses, excluding non-cash compensation expense(525) (464) (61) (1,543) (1,349) (194)
Selling, general and administrative, excluding non-cash compensation expense(95) (76) (19) (302) (239) (63)
Inventory valuation adjustments(86) (37) (49) (30) (143) 113
Adjusted EBITDA related to unconsolidated affiliates279
 240
 39
 765
 711
 54
Other(7) 25
 (32) 22
 75
 (53)
Segment Adjusted EBITDA$1,744
 $1,390
 $354
 $4,757
 $4,172
 $585
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.
•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

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•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.
The following analysis of segment operating results includes a measure of segment margin. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the following sections include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
Intrastate Transportation and Storage
Three Months Ended
March 31,		 
20232022Change
Natural gas transported (BBtu/d)14,697 13,973 724 
Withdrawals from storage natural gas inventory (BBtu)6,000 21,858 (15,858)
Revenues$1,290 $1,632 $(342)
Cost of products sold985 1,171 (186)
Segment margin305 461 (156)
Unrealized losses on commodity risk management activities174 46 128 
Operating expenses, excluding non-cash compensation expense(62)(63)1 
Selling, general and administrative expenses, excluding non-cash compensation expense(14)(12)(2)
Adjusted EBITDA related to unconsolidated affiliates6 6 — 
Other— 6 (6)
Segment Adjusted EBITDA$409 $444 $(35)
Volumes. For the three months ended September 30, 2017March 31, 2023 compared to the same period last year, transported volumes increased primarily due to increased utilization on our Enable Oklahoma Intrastate Transmission system and higher production in the Haynesville Shale.

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Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
Three Months Ended
March 31,		 
20232022Change
Transportation fees$216 $215 $1 
Natural gas sales and other (excluding unrealized gains and losses)176 209 (33)
Retained fuel revenues (excluding unrealized gains and losses)15 32 (17)
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)72 51 21 
Unrealized losses on commodity risk management activities and fair value inventory adjustments(174)(46)(128)
Total segment margin$305 $461 $(156)
Segment Adjusted EBITDA. For the three months ended March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP increasedour intrastate transportation and storage segment decreased due to the net impactimpacts of the following:

•a decrease of $33 million in realized natural gas sales and other primarily due to lower pipeline optimization;
•a decrease of $17 million in retained fuel revenues related to lower natural gas prices; and
•an increase of $30$2 million in ETP’s intrastate transportationselling, general and storage operations resulting from an increase of $29 million due to higher realized gains from pipeline optimization activity and an increase of $9 million in storage margin. These increases were offset by a decrease in transportation fees due to renegotiated contracts;
an increase of $42 million in ETP’s midstream operations primarily due to a $24 million increase in non-fee based margins due to higher realized crude oil and NGL prices and a $31 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;
an increase of $40 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $20 million,administrative expenses primarily due to higher volumes on Texas NGL pipelineslegal fees and the ramp-up of volumes on the Mariner East system; insurance expenses; partially offset by
•an increase of $21 million in fractionation and refinery servicesstorage margin of $14 million, primarily due to higher NGL volumes from most major producing regions; and storage optimization;
•an increase of $1 million in terminal services margin of $7 milliontransportation fees primarily due to higher terminal volumes from the Mariner NGL projects; partially offset by an increasefees on our Haynesville and Oklahoma assets; and
•a decrease of $1 million in operating expenses duerelated to a legal settlement and a quarterly$9 million decrease in cost of fuel consumption, offset by increases in ad valorem tax true-up;taxes, outside services, utilities and materials expenses.
an increase of $227 million in ETP’s crude oil transportationInterstate Transportation and services operations due to an increase of $194 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 $28 million from existing assets due to increased volumes throughout the system; and an increase of $18 million due to the impact of LIFO accounting; 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; andStorage
an increase of approximately $20 million in ETP’s all other operations, primarily due to an increase of $25 million in Adjusted EBITDA related to ETP’s investment in PES of $34 million, offset by decrease of $9 million from ETP’s investment in Sunoco LP. In addition,
Three Months Ended
March 31,
20232022Change
Natural gas transported (BBtu/d)16,818 15,098 1,720 
Natural gas sold (BBtu/d)22 41 (19)
Revenues$634 $566 $68 
Cost of products sold2 19 (17)
Segment margin632 547 85 
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(186)(171)(15)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(31)(31)— 
Adjusted EBITDA related to unconsolidated affiliates121 88 33 
Other— 20 (20)
Segment Adjusted EBITDA$536 $453 $83 
Volumes. For the three months ended September 30, 2017 experienced an increase of $7 million from commodity trading activities and an increase of $4 million from ETP’s compression operations. These increases were partially offset by higher transaction related expenses, and operating and maintenance expenses from an equipment lease buyout; partially offset by
a decrease of $5 million in ETP’s interstate transportation and storage operations dueMarch 31, 2023 compared to an aggregate $12 million decrease in revenue, including decreases on the Panhandle, Trunkline and Transwestern pipelinessame period last year, transported volumes increased primarily due to lack of customer demand driven by weak spreads and mild weather, and a decrease of $3 million revenues on the Tiger pipeline due to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipelineour Gulf Run Pipeline being placed in partial service in August 2017December 2022, as well as more capacity sold and by higher income from unconsolidated joint ventures of $9 million primarilyutilization on our Transwestern, Panhandle and Trunkline systems due to a legal settlement and lower operating expenses on Citrus.increased demand.
Segment Adjusted EBITDA. For the ninethree months ended September 30, 2017March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETPour interstate transportation and storage segment increased due to the net impactimpacts of the following:
•an increase of $19$85 million in ETP’s intrastatesegment margin primarily due to a $28 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and storage operationshigher rates, a $28 million increase resulting from a $63

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our Gulf Run Pipeline being placed in service in December 2022, an $18 million increase due to higher realized gains from pipeline optimization offset by a $44 million decreasethe realization in transportation fees due to renegotiated contracts;
an increasethe current period of $213 million in ETP’s midstream operations primarily duecertain amounts related to a $151shipper bankruptcy, a $16 million increase from sales of operational gas and a $7 million increase in non-fee based margins due to higher realized crude oil and NGL prices and increased volumes in the Permian region and a $93 million increase in fee-based revenues due to minimum volume commitments in South Texas as well as increased volumes in the Permian and Northeast regions, and recent acquisitions, including PennTex.parking revenue. These increases in gross margin were partially offset by increasesa $12 million decrease in operating expenses of $17 millionreservation fees primarily due to recent acquisitionsslightly lower volumes on our Rover system; and increases in selling, general and administrative expenses due to a decrease in capitalized overhead, an increase in shared services allocation, an increase in insurance allocation and additional costs from the PennTex acquisition;
•an increase of $124 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $91 million, primarily due to higher volumes on Texas NGL pipelines and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $56 million, primarily due to higher NGL volumes from most major producing regions; and an increase of $22 million in marketing margin (excluding changes in unrealized gains of $50 million) primarily due to the timing of the recognition of margin from optimization activities; partially offset by an increase of $39 million in operating expenses primarily due to increased utilities costs associated with our fourth fractionator at Mont Belvieu and the Mariner project ramp up at the Marcus Hook Industrial Complex; and

an increase of $309 million in ETP’s crude oil transportation and services operations due to an increase of $389 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; and an increase of $11 million from existing assets due to increased volumes throughout the system; 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 $48 million in ETP’s interstate transportation and storage operations due to an aggregate $63 million decrease in revenue, including decreases on the Panhandle, Trunkline and Transwestern pipelines primarily due to lack of customer demand driven by weak spreads and mild weather, and a decrease of $17 million revenues on the Tiger pipeline due to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipeline being placed in partial service in August 2017 and by lower operating expenses and selling, general and administrative expenses as well as an increase in income from unconsolidated joint ventures of $7 million primarily due to a legal settlement and lower operating expenses on Citrus offset by lower earnings from Midcontinent Express; and
a decrease of approximately $32 million in ETP’s all other operations, primarily due to a decrease of $66 million related to the termination of ETP’s management fees paid by ETE that ended in 2016 and an increase of $39 million in transaction related expenses partially offset by an increase of $35$33 million in Adjusted EBITDA related to unconsolidated affiliates primarily comprising increases ofdue to a $29 million increase from ETP’s investment in PESour MEP joint venture as a result of higher revenue due to capacity sold at higher rates, and a $3 million increase from ETP’s investment in Sunoco LP, our Southeast Supply Header joint venture resulting from higher revenue due to higher contracted volumes and higher rates; partially offset by
•an increase of $15 million in operating expenses primarily due to an $8 million increase resulting from commodity trading activitiesour Gulf Run Pipeline being placed in service in December 2022 and lower expensesan aggregate $7 million increase in right-of-way expense, materials, outside services and other direct expenses; and
•a decrease of $20 million in other primarily due to the realization in the prior period of certain amounts related to ETP’s compression operations.a shipper bankruptcy.
Investment in Sunoco LPMidstream
Three Months Ended
March 31,
20232022Change
Gathered volumes (BBtu/d)19,750 17,333 2,417 
NGLs produced (MBbls/d)811 757 54 
Equity NGLs (MBbls/d)40 42 (2)
Revenues$2,754 $3,925 $(1,171)
Cost of products sold1,781 2,885 (1,104)
Segment margin973 1,040 (67)
Unrealized gains on commodity risk management activities— (2)2 
Operating expenses, excluding non-cash compensation expense(288)(234)(54)
Selling, general and administrative expenses, excluding non-cash compensation expense(50)(44)(6)
Adjusted EBITDA related to unconsolidated affiliates5 9 (4)
Other1 38 (37)
Segment Adjusted EBITDA$641 $807 $(166)
 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Revenues$2,555
 $2,167
 $388
 $7,330
 $5,918
 $1,412
Cost of products sold2,304
 1,975
 329
 6,730
 5,290
 1,440
Operating expenses, excluding non-cash compensation expense(62) (62) —
 (182) (171) (11)
Selling, general and administrative, excluding non-cash compensation expense(21) (42) 21
 (84) (119) 35
Inventory valuation adjustments(56) 1
 (57) (8) (60) 52
Unrealized gains (losses) on commodity risk management activities(5) 6
 (11) (5) 9
 (14)
Adjusted EBITDA from discontinued operations92
 93
 (1) 253
 220
 33
Other—
 1
 (1) —
 5
 (5)
Segment Adjusted EBITDA$199
 $189
 $10
 $574
 $512
 $62
Segment Adjusted EBITDA. Volumes.For the three months ended September 30, 2017March 31, 2023 compared to the same period last year, gathered volumes and NGL production increased primarily due to increased producer activity in all regions.
Segment Margin. The components of our midstream segment gross margin were as follows:
Three Months Ended
March 31,
20232022Change
Gathering and processing fee-based revenues$763 $697 $66 
Non-fee-based contracts and processing210 341 (131)
Unrealized gains on commodity risk management activities— 2 (2)
Total segment margin$973 $1,040 $(67)
Segment Adjusted EBITDA. For the three months ended March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in Sunoco LPour midstream segment increaseddecreased due to the net impacts of the following:
•a decrease of $138 million in non-fee-based margin due to unfavorable natural gas prices of $70 million and NGL prices of $68 million;
•an increase of $54 million in wholesale motor fuel revenueoperating expenses due to a higher sales price per wholesale motor fuel gallon,$22 million increase in repairs, material and equipment rental costs, a $14 million increase in employee costs, a $9 million increase in maintenance project costs, a $6 million increase

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from the Woodford Express acquisition and the Grey Wolf processing plant coming online in late 2022 and a $2 million increase in ad valorem taxes;
•an increase in wholesale motor fuel gallons sold offset by higher cost of products sold, excluding a $56$6 million favorable inventory adjustment change from 2016;
a net increase in other revenue consisting of merchandise, rental income and retail motor fuel of $8 million; and
a decrease in selling, general and administrative expenses due to a $3 million increase in legal and insurance expenses, a $2 million increase in employee and IT costs and a $1 million increase in corporate allocations;
•a decrease of $21$4 million in Adjusted EBITDA related to unconsolidated affiliates due to the sale of the Partnership’s membership interest in Ranch Westex JV LLC in 2022; and
•a decrease of $37 million in other primarily due to higher coststhe realization in 2016the prior period of certain amounts related to relocation, employee termination,a shipper bankruptcy; partially offset by
•an increase of $66 million in fee-based margin due to increased throughput across all regions; and
•an increase of $7 million in non-fee-based margin due to increased producer activity in the Mid-continent/Panhandle and Permian regions.
NGL and Refined Products Transportation and Services
Three Months Ended
March 31,
20232022Change
NGL transportation volumes (MBbls/d)1,984 1,752 232 
Refined products transportation volumes (MBbls/d)501 496 5 
NGL and refined products terminal volumes (MBbls/d)1,344 1,180 164 
NGL fractionation volumes (MBbls/d)949 804 145 
Revenues$5,603 $6,277 $(674)
Cost of products sold4,402 5,356 (954)
Segment margin1,201 921 280 
Unrealized gains on commodity risk management activities(31)(5)(26)
Operating expenses, excluding non-cash compensation expense(221)(202)(19)
Selling, general and administrative expenses, excluding non-cash compensation expense(38)(35)(3)
Adjusted EBITDA related to unconsolidated affiliates28 21 7 
Segment Adjusted EBITDA$939 $700 $239 
Volumes. For the three months ended March 31, 2023 compared to the same period last year, NGL transportation volumes increased primarily due to higher volumes from the Permian region, higher volumes on our Mariner East pipeline system and higher contract laborvolumes on our export pipelines into our Nederland Terminal.
NGL and professional feesrefined products terminal volumes increased for the three months ended March 31, 2023 compared to the same period last year primarily due to higher volumes on our export pipelines into our Nederland Terminal, higher volumes on our Mariner East pipelines into our Marcus Hook Terminal and higher volumes through our Texas marketing terminals.
The aforementioned increase in transportation volumes also led to higher fractionated volumes at our Mont Belvieu, Texas fractionation facility for the three months ended March 31, 2023 compared to the same period last year.

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Segment Margin. The components of our NGL and refined products transportation and services segment margin were as Sunoco LP transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas, to Dallas during 2016.follows:
Three Months Ended
March 31,
20232022Change
Transportation margin$562 $479 $83 
Fractionators and refinery services margin210 185 25 
Terminal services margin200 151 49 
Storage margin79 72 7 
Marketing margin119 29 90 
Unrealized gains on commodity risk management activities31 5 26 
Total segment margin$1,201 $921 $280 
Segment Adjusted EBITDA. For the ninethree months ended September 30, 2017March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in Sunoco LPour NGL and refined products transportation and services segment increased due to the net impactimpacts of the following:

•an increase of $90 million in wholesale motor fuel revenue due to a higher sales price per wholesale motor fuel gallon, and an increase in wholesale motor fuel gallons sold offset by higher cost of products sold primarily due to an unfavorable inventory adjustment changes;
a decrease in selling, general and administrative expenses of $35 millionmarketing margin primarily due to higher costsgains of $52 million from the optimization of NGL and refined product inventories and a $30 million increase in 2016 related to relocation, employee termination,northeast blending and higher contract labor and professional fees as Sunoco LP transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas, to Dallas during 2016; andoptimization;
•an increase of $83 million in adjusted EBITDA from discontinued operations of $33 milliontransportation margin primarily due to a $52 million increase resulting from higher y-grade throughput and higher rates driven by contractual rate escalations on our Texas pipeline system, a $17 million increase resulting from higher throughput on our Mariner East pipelines and a $12 million increase from higher exported volumes feeding into our Nederland Terminal;
•an increase of $73$49 million in the gross profit offset by terminal services margin primarily due to a $25 million increase from higher throughput at our Marcus Hook Terminal and a $23 million increase from higher export volumes loaded at our Nederland Terminal;
•an increase of $48$25 million in fractionators and refinery services margin primarily due to a $29 million increase from higher volumes and higher rates driven by contractual rate escalations. This increase was partially offset by a $5 million decrease from a less favorable pricing environment impacting our refinery services business;
•an increase of $7 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher volumes on the Explorer and Wolverine pipelines; and
•an increase of $7 million in storage margin primarily due to fees generated from exported volumes; partially offset by
•an increase of $19 million in operating expenses primarily due to a $6 million increase in employee costs, a $5 million increase in maintenance project costs and a $7 million increase in materials costs; and
•an increase of $3 million in selling, general and administrative expenses primarily due to increases in overhead expenses and insurance costs.

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Crude Oil Transportation and Services
Three Months Ended
March 31,
20232022Change
Crude transportation volumes (MBbls/d)4,238 4,216 22 
Crude terminal volumes (MBbls/d)2,940 2,765 175 
Revenues$6,080 $5,926 $154 
Cost of products sold5,374 5,179 195 
Segment margin706 747 (41)
Unrealized losses on commodity risk management activities2 11 (9)
Operating expenses, excluding non-cash compensation expense(153)(137)(16)
Selling, general and administrative expenses, excluding non-cash compensation expense(31)(30)(1)
Adjusted EBITDA related to unconsolidated affiliates1 1 — 
Other1 1 — 
Segment Adjusted EBITDA$526 $593 $(67)
Volumes. For the three months ended March 31, 2023 compared to the same period last year, crude transportation volumes were higher on our Texas pipeline systems due to higher Permian Basin crude production and the Ted Collins Link going in service in the second quarter of 2022. Volumes on our Bayou Bridge Pipeline were also higher, partly offset by lower volumes on our Bakken Pipeline due to production impacts from Winter Storm Elliot in the fourth quarter of 2022 which also impacted January 2023 production. Crude terminal volumes were higher due to stronger export demand and refinery utilization.
Segment Adjusted EBITDA. For the three months ended March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to discontinuedour crude oil transportation and services segment decreased primarily due to the net impacts of the following:
•a decrease of $50 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due a $48 million decrease from our crude oil acquisition and marketing business due to the timing of optimization gains; and
•an increase of $16 million in operating expenses primarily due to an $8 million increase in volume-driven expenses, a $5 million increase primarily from maintenance project expenses and a $4 million increase in employee costs.
Investment in Sunoco LP
Three Months Ended
March 31,
20232022Change
Revenues$5,362 $5,402 $(40)
Cost of products sold4,987 4,972 15 
Segment margin375 430 (55)
Unrealized gains on commodity risk management activities(11)(9)(2)
Operating expenses, excluding non-cash compensation expense(97)(97)— 
Selling, general and administrative expenses, excluding non-cash compensation expense(25)(22)(3)
Adjusted EBITDA related to unconsolidated affiliates3 2 1 
Inventory valuation adjustments(29)(120)91 
Other5 7 (2)
Segment Adjusted EBITDA$221 $191 $30 
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

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Segment Adjusted EBITDA. For the three months ended March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment reflected an increase in the profit on motor fuel sales of $26 million, primarily due to a 4% increase in profit per gallon sold and a 9% increase in gallons sold.
Investment in USAC
Three Months Ended
March 31,
20232022Change
Revenues$197 $163 $34 
Cost of products sold34 25 9 
Segment margin163 138 25 
Operating expenses, excluding non-cash compensation expense(32)(29)(3)
Selling, general and administrative expenses, excluding non-cash compensation expense(13)(11)(2)
Segment Adjusted EBITDA$118 $98 $20 
The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased primarily due to higher average rates across USAC’s fleet and higher revenue-generating horsepower.
All Other
Three Months Ended
March 31,
20232022Change
Revenues$544 $715 $(171)
Cost of products sold502 614 (112)
Segment margin42 101 (59)
Unrealized (gains) losses on commodity risk management activities(4)4 (8)
Operating expenses, excluding non-cash compensation expense(6)(34)28 
Selling, general and administrative expenses, excluding non-cash compensation expense(9)(17)8 
Other and eliminations20 — 20 
Segment Adjusted EBITDA$43 $54 $(11)
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 three months ended March 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased primarily due to the net impacts of the following:
•a decrease of $30 million due to the sale of Energy Transfer Canada in 2022; and
•a decrease of $5 million due to an unfavorable environment for our power trading activities; partially offset by
•a decrease of $9 million in mergers and acquisition expense; and
•an increase in other operating expenses of $11$17 million primarily attributable to the acquisition of the fuels business from Emerge Energy Services LP in August of 2016 as well as increases of utilities, maintenance expenses, property taxes and credit card processing fees in our retail business.
Investment in Lake Charles LNGnatural gas marketing subsidiary.

48
 Three Months Ended
September 30,		   Nine Months Ended
September 30,		  
 2017 2016 Change 2017 2016 Change
Revenues$49
 $50
 $(1) $148
 $148
 $—
Operating expenses, excluding non-cash compensation expense(6) (4) (2) (15) (13) (2)
Selling, general and administrative, excluding non-cash compensation expense—
 (1) 1
 (2) (2) —
Segment Adjusted EBITDA$43
 $45
 $(2) $131
 $133
 $(2)
Lake Charles LNG derives all
Table of its revenue from a long-term contract with BG Group plc.Contents
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 our subsidiaries 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 incentive distributions to be received, and we may agree to do so in the future, in connection with transactions or otherwise.
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 its distributions from 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.
We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.
ETP
ETP’sOur ability to satisfy its 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.
We currently expect capital expenditures in 2023 to be within the controlfollowing 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 storage (1)
275 325 175 185 
Midstream850 900 190 200 
NGL and refined products transportation and services550 575 120 130 
Crude oil transportation and services (1)
175 200 140 145 
All other (including eliminations)25 50 65 70 
Total capital expenditures$1,900 $2,100 $740 $790 
(1)Includes capital expenditures related to our proportionate share of ETP’s management.the Bakken, Rover and Bayou Bridge pipeline joint ventures, and the Orbit Gulf Coast NGL Exports joint venture.
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 in a timely, manner, higher steel prices and other factors beyond ETP’sour control. However, ETPwe have included these factors in itsour anticipated growth capital expenditures for each year.
ETPWe generally funds itsfund maintenance capital expenditures and distributions with cash flows from operating activities. ETPWe generally fundsexpect to fund growth capital expenditures with proceeds of borrowings under the ETP Credit Facility, long-term debt, the issuance of additional ETP common units, dropdown proceeds or the monetization of non-core assets or a combination thereof.
Sunoco LP
Sunoco LP’s ability to satisfy its obligations and pay distributions to its unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of Sunoco LP’s management.our credit facilities, along with cash from operations.
Sunoco LP currently expects to spend approximatelyinvest at least $150 million onin growth capital expenditures and $70approximately $65 million onin maintenance capital expenditures for the full year 2017.2023.
USAC currently plans to spend approximately $26 million in maintenance capital expenditures and spend between $260 million and $270 million in expansion capital expenditures for the full year 2023.
Cash Flows
Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our operating entities 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 unit-based compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from the construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities,

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the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchasespurchase and sales of inventories and the timing of advances and deposits received from customers.
NineThree months ended September 30, 2017March 31, 2023 compared to ninethree months ended September 30, 2016March 31, 2022. Cash provided by operating activities during 20172023 was $3.30$3.35 billion as compared to $2.22$2.37 billion for 2016. Net2022, and net income was $1.21$1.45 billion for 2023 and $801 million$1.49 billion for 2017 and 2016, respectively.2022. The difference between net income and the net cash provided by operating activities for the ninethree months ended September 30, 2017 and 2016,March 31, 2023 primarily consisted of non-cash items totaling $1.40 billion and $898 million, respectively, and net changes in operating assets and liabilities (net of $222effects of acquisitions) of $801 million and $48 million, respectively. The nine months ended September 30, 2016, included a $308 million impairment of investment in an unconsolidated affiliate.other non-cash items totaling $1.04 billion.
The non-cash activity in 20172023 and 20162022 consisted primarily of depreciation, depletion and amortization of $1.84$1.06 billion and $1.60$1.03 billion, respectively, non-cash compensation expense of $37 million and $36 million, respectively, favorable inventory valuation adjustments of $29 million and $120 million, respectively, deferred income taxes of $53 million and $32 million, respectively, and impairment losses of $1 million and $300 million, respectively. Non-cash activity also included equity in earnings of unconsolidated affiliates of $228$88 million and $205$56 million respectively, inventory valuation adjustments of $38in 2023 and 2022, respectively.
Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $87 million in 2023 and $203$44 million respectively, deferred income taxes of $120 million and $139 million, respectively, and unit-based compensation expense of $76 million and $46 million, respectively.in 2022.
Cash paid for interest, net of interest capitalized, was $1.41 billion and $1.43 billion for the nine months ended September 30, 2017 and 2016, respectively.
Capitalized interest was $177$406 million and $148$366 million for the ninethree months ended September 30, 2017March 31, 2023 and 2016,2022, respectively.

Interest capitalized was $15 million and $33 million for the three months ended March 31, 2023 and 2022, respectively.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid infor acquisitions, capital expenditures, cash distributions fromcontributions to our joint ventures and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.
NineThree months ended September 30, 2017March 31, 2023 compared to ninethree months ended September 30, 2016. March 31, 2022. Cash used in investing activities during 20172023 was $4.76 billion as$803 million compared to cash used in investing activities $6.08$1.27 billion for 2016.2022. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 20172023 were $6.10 billion. This compares$837 million compared to total$732 million for 2022. Additional detail related to our capital expenditures (excludingis provided in the allowancefollowing table. In 2022, we paid $325 million in cash for equity funds used during constructionthe acquisition of Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC) and Sunoco LP paid a cash deposit of $264 million related to its acquisition of a transmix processing and terminal facility.
The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover and Bayou Bridge pipeline joint ventures, and the Orbit Gulf Coast NGL Exports joint venture, net of contributions in aid of construction costs) on an accrual basis for 2016 of $5.88 billion. During the ninethree months ended September 30, 2017, we had proceeds from transactionsMarch 31, 2023:
Capital Expenditures Recorded During Period
GrowthMaintenanceTotal
Intrastate transportation and storage$22 $13 $35 
Interstate transportation and storage58 24 82 
Midstream191 44 235 
NGL and refined products transportation and services116 30 146 
Crude oil transportation and services13 25 38 
Investment in Sunoco LP29 8 37 
Investment in USAC51 5 56 
All other (including eliminations)7 13 20 
Total capital expenditures$487 $162 $649 

50
Table of $1.4 billion.Contents
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. Distribution increasesDistributions increase between the periods were based on increases in distribution rates, increases in the number of common units outstanding at our subsidiaries andor increases in the number of our common units outstanding.distribution rate.
NineThree months ended September 30, 2017March 31, 2023 compared to ninethree months ended September 30, 2016.March 31, 2022. Cash used in financing activities during 20172023 was $1.30$2.47 billion as compared to cash provided by financing activities of $3.92 billion$324 million for 2016. In 2017, ETE received $2.20 billion in net proceeds from offerings of ETE common units and subsidiary common units as compared to $2.10 billion in 2016. In 2016, Sunoco Logistics received $1.31 billion in net proceeds from offerings of their common units.2022. During 2017,2023, we had a consolidated net increasedecrease in our debt level of $1.40$1.02 billion as compared to a net increase of $4.33 billion$230 million for 2016. 2022.
In 2017,2023 and 2022, we paid net proceeds on affiliates notes in the amount of $255 million. We have paid distributions of $752$1.00 billion and $608 million, respectively, to our partners. In 2023 and 2022, we paid distributions of $441 million and $780$307 million, respectively, to noncontrolling interests. In 2023 and 2022, we paid distributions of $12 million in both periods to our partnersredeemable noncontrolling interests.
In 2023 and 2022, we received capital contributions of $3 million and $373 million, respectively, in 2017 and in 2016, respectively. Our subsidiaries have paid distributions tocash from noncontrolling interest of $2.16 billion and $2.03 billion in 2017 and 2016, respectively.

interests.
Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
March 31,
2023		December 31,
2022
Energy Transfer Indebtedness:
Notes and Debentures (1)
$37,318 $39,468 
Five-Year Credit Facility1,957 793 
Subsidiary Indebtedness:
Transwestern Senior Notes250 250 
Bakken Senior Notes1,850 1,850 
Sunoco LP Senior Notes and lease-related obligations2,694 2,694 
USAC Senior Notes1,475 1,475 
HFOTCO Tax Exempt Notes225 225 
Revolving credit facilities:
Sunoco LP Credit Facility800 900 
USAC Credit Facility709 646 
Other long-term debt3 3 
Net unamortized premiums, discounts, and fair value adjustments171 183 
Deferred debt issuance costs(221)(225)
Total debt47,231 48,262 
Less: current maturities of long-term debt2 2 
Long-term debt, less current maturities$47,229 $48,260 
 September 30, 2017 December 31, 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 Secured Term Loan, due December 2, 20192,200
 2,190
ETE Senior Secured Revolving Credit Facility1,191
 875
Subsidiary Indebtedness:   
ETP Senior Notes20,540
 19,440
Panhandle Senior Notes1,085
 1,085
Sunoco, Inc. Senior Notes65
 465
Sunoco Logistics Senior Notes7,600
 5,350
Transwestern Senior Notes575
 657
Sunoco LP Senior Notes, Term Loan and lease-related obligation3,581
 3,561
Credit Facilities and Commercial Paper:   
ETLP $3.75 billion Revolving Credit Facility due November 2019 (1)
2,056
 2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 (2)
35
 1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017 (3)
—
 630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019644
 1,000
Bakken Term Note2,500
 1,100
PennTex $275 million Revolving Credit Facility due December 2019—
 168
Other Long-Term Debt5
 31
Unamortized premiums and fair value adjustments, net65
 101
Deferred debt issuance costs(268) (257)
Total45,211
 43,802
Less: Current maturities of long-term debt716
 1,194
Long-term debt and notes payable, less current maturities$44,495
 $42,608
(1)
Includes $2.06 billion and $777 million of commercial paper outstanding at September 30, 2017 and December 31, 2016, respectively.
(2)
Includes $50 million of commercial paper outstanding at December 31, 2016.
(3)
Sunoco Logistics’ $1.00 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics had the ability and intent to refinance such borrowings on a long-term basis. This 364-Day Credit Facility was terminated and repaid in May 2017.
Senior Notes and Term Loan
Energy Transfer Equity, L.P. Senior Notes Offering 
In October 2017, ETE issued $1(1)As of March 31, 2023, this balance included a total of $2.96 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds fromon or before March 31, 2024, which were classified as long-term as management has the offering are intendedintent and ability to be used to repayrefinance the borrowings on a portionlong-term basis.
Senior Notes - Recent Transactions
In the first quarter of the outstanding indebtedness under its term loan facility and for general partnership purposes.
ETE Term Loan Facility
On February 2, 2017,2023, 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.

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 ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, 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 Waiver
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 September 30, 2017, the balance on the term loan was $1.24 billion.
ETP Senior Notes Redemption
In October 2017, ETP redeemed all of the outstanding $500$350 million aggregate principal amount of ETLP’s 6.50% senior notesits 3.45% Senior Notes due July 2021 and all of the outstanding $700January 2023, $800 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.
ETPits 3.60% 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 2023 and $1.50$1.00 billion aggregate principal amount of 5.40% senior notesits 4.25% Senior Notes due 2047. The $2.22 billion netMarch 2023 using 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 Logisticsits Five-Year Credit Facility (described(defined below) and for general partnership purposes..

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Credit Facilities and Commercial Paper
Parent Company Credit Facility
Indebtedness under the Parent Company 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 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 Revolver Lenders have committed to provide advances up to an aggregate principal amount of $1.5 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 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 September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.
ETLPFive-Year Credit Facility
The ETLPPartnership’s revolving credit facility (the “Five-Year Credit FacilityFacility”) allows for unsecured borrowings of up to $3.75$5.00 billion and matures in November 2019.April 2027. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of which was commercial paper.
Sunoco Logistics Credit Facilities
ETP maintains the Sunoco Logistics $2.50 billion unsecured revolving credit facility (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco LogisticsFive-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $3.25$7.00 billion under certain conditions.
As of September 30, 2017,March 31, 2023, the Sunoco LogisticsFive-Year Credit Facility had $35 million$1.96 billion of outstanding borrowings.
In December 2016, Sunoco Logistics entered into an agreementborrowings, of which $757 million consisted of commercial paper. The amount available for a 364-day maturityfuture borrowings was $3.01 billion, after accounting for outstanding letters of credit facility (“364-Day Credit Facility”), due to maturein the amount of $32 million. The weighted average interest rate on the earliertotal amount outstanding as of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit FacilityMarch 31, 2023 was terminated and repaid in May 2017.6.05%.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amountAs 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 ofMarch 31, 2023, 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 September 30, 2017, the Sunoco LP credit facility had $644$800 million of outstanding borrowings and $19$7 million in standby letters of credit.credit and matures in April 2027. The unused availabilityamount available for future borrowings at March 31, 2023 was $693 million. The weighted average interest rate on the revolver at September 30, 2017total amount outstanding as of March 31, 2023 was $847 million.6.61%.
BakkenUSAC Credit Facility
In August 2016, ETP, Sunoco Logistics and Phillips 66 completed project-level financingAs of the Bakken Pipeline. The $2.50 billionMarch 31, 2023, USAC’s credit facility, provides substantially allwhich matures in December 2026, had $709 million of the remaining capital necessary to complete the projects.outstanding borrowings and no outstanding letters of credit. As of September 30, 2017, $2.5 billionMarch 31, 2023, USAC had $891 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $375 million. The weighted average interest rate on the total amount outstanding as of March 31, 2023 was outstanding under this credit facility.7.38%.
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.
Compliance with our Covenants Related to Our Credit Agreements
We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our respective creditdebt agreements as of September 30, 2017.March 31, 2023.
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 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 theour General Partner that is necessary or appropriate to provide for future cash requirements.
Following are distributionsCash Distributions on Energy Transfer Common Units
Distributions declared and/or paid by uswith respect to Energy Transfer common units subsequent to December 31, 2016:2022 were as follows:
Quarter Ended Record Date Payment Date Rate
    
December 31, 2016 (1)
 February 7, 2017 February 21, 2017 $0.2850
March 31, 2017 (1)
 May 10, 2017 May 19, 2017 0.2850
June 30, 2017 (1)
 August 7, 2017 August 21, 2017 0.2850
September 30, 2017 November 7, 2017 November 20, 2017 0.2950
(1)
Quarter Ended		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 Record DatePayment DateRate
December 31, 2022February 7, 2023February 21, 2023$0.3050 
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 9, ETE Series A Convertible Preferred Units.2023
Our distributions declared with respect to our Convertible Units during the year ended December 31, 2016 were as follows:
Quarter Ended          Record Date Payment Date  Rate
December 31, 2016 February 7, 2017 February 21, 2017 $0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
The total amounts of distributions declared for the periods presented (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):
 Nine Months Ended
September 30,
 2017 2016
Limited Partners$757
 $721
General Partner interest2
 2
Total Parent Company distributions$759
 $723
Cash Distributions Received by the Parent Company
The Parent Company’s cash available for distributions historically has been primarily generated from its direct and indirect interests in ETP and Sunoco LP. Lake Charles LNG also contributes to the Parent Company’s cash available for distributions.
As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

May 8, 2023May 22, 2023$0.3075 
Percentage of Total Distributions to IDRsQuarterly Distribution Rate Target Amounts
Minimum quarterly distribution—%$0.075
First target distribution—%$0.075 to $0.0833
Second target distribution13%$0.0833 to $0.0958
Third target distribution35%$0.0958 to $0.2638
Fourth target distribution48%Above $0.2638
The total amountCash Distributions on Energy Transfer Preferred Units
Distributions declared on the Energy Transfer Preferred Units 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)
December 31, 2022February 1, 2023February 15, 2023$31.250 $33.125 $0.4609 $0.4766 $0.475 $— $— $— 
March 31, 2023May 1, 2023May 15, 202321.982 — 0.4609 0.4766 0.475 33.750 35.625 32.500 
(1)Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis. See additional information on Series A distributions below.

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Distributions on the Series A Preferred Units previously accrued at a fixed rate of 6.250% per annum of the liquidation preference of $1,000. Beginning February 15, 2023, the Series A Preferred Units have a floating distribution rate set each quarterly distribution period at a percentage of the $1,000 liquidation preference equal to the Parent Company from its limited partner interests, general partner interestthen-current three-month LIBOR plus a spread of 4.028% per annum. Distributions on Series A Preferred Units were previously payable semi-annually in arrears until February 15, 2023, and, incentive distributions (shownafter February 15, 2023, quarterly in arrears, when, as, and if declared by our General Partner out of legally available funds for such purpose.
Description of Energy Transfer Preferred Units
A summary of the period to which they relate) fordistribution and redemption rights associated with the periods ended as noted belowEnergy Transfer Preferred Units is as follows:
 Nine Months Ended
September 30,
 2017 2016
Distributions from ETP:   
Limited Partner interests$45
 $8
Class H Units—
 263
General Partner interest12
 24
IDRs1,204
 1,012
IDR relinquishments net of Class I Unit distributions(482) (271)
Total distributions from ETP779
 1,036
Distributions from Sunoco LP   
Limited Partner interests6
 6
IDRs63
 60
Series A Preferred15
 —
Total distributions from Sunoco LP84
 66
Total distributions received from subsidiaries863
 1,102
ETE has agreed to relinquish its right to the following amounts of incentive distributions from the ETPincluded in future periods:
  Total Year
2017 (remainder) $173
2018 153
2019 128
Each year beyond 2019 33
ETE may agree to relinquish its rights to additional amounts of incentive distributionsNote 9 in future periods. Please see “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016. ETE may agree to relinquish its rights to a portion of its incentive distributions in future periods without the consent of ETE unitholders.“Item 1. Financial Statements.”
Cash Distributions Paid by Subsidiaries
CertainThe Partnership’s consolidated financial statements include Sunoco LP and USAC, both of which are master limited partnerships, as well as other non-wholly-owned consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less(less appropriate reserves determined by the boardboards of directors of their respective general partners.
Cash Distributions Paid by ETP
Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership, which was Sunoco Logistics’ limited partnership agreement priorpartners) subsequent to the Sunoco Logistics Merger. Under the 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 general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” 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.
The following table shows the target distribution levels and distribution "splits" between the general partner and the holders of 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.
For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.
Following are distributions declared and/or paid by ETP subsequent to the Sunoco Logistics Merger:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 15, 2017 $0.5350
June 30, 2017 August 7, 2017 August 14, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
The total amount of distributions declared during the periods presented were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):
 Nine Months Ended
September 30,
 2017 2016
 ETP Energy Transfer Partners, L.P. Sunoco Logistics
Limited Partners:     
Common Units held by public$1,794
 $1,607
 $353
Common Units held by ETP—
 —
 100
Common Units held by ETE45
 8
 —
Class H Units held by ETE—
 263
 —
General Partner interest12
 24
 11
Incentive distributions held by ETE1,204
 1,012
 289
IDR relinquishments(482) (271) (8)
Total distributions declared to partners$2,573
 $2,643
 $745

quarter.
Cash Distributions Paid by Sunoco LP
Following are distributionsDistributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 2016:2022 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2022February 7, 2023February 21, 2023$0.8255 
March 31, 2023May 8, 2023May 22, 20230.8420 
Cash Distributions Paid by USAC
Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2022 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2022January 23, 2023February 3, 2023$0.525 
March 31, 2023April 24, 2023May 5, 20230.525 
Quarter Ended Record Date Payment Date Rate
December 31, 2016 February 13, 2017 February 21, 2017 $0.8255
March 31, 2017 May 9, 2017 May 16, 2017 0.8255
June 30, 2017 August 7, 2017 August 15, 2017 0.8255
September 30, 2017 November 7, 2017 November 14, 2017 0.8255
The total amounts of Sunoco LP distributions declared for the periods presented (all from Available Cash from Sunoco LP’s operating surplus and are shown in the period with respect to which they relate):
 Nine Months Ended
September 30,
 2017 2016
Limited Partners:   
Common units held by public$133
 $122
Common and subordinated units held by ETP150
 107
Common and subordinated units held by ETE6
 6
General Partner interest and Incentive distributions63
 60
Series A Preferred15
 —
Total distributions declared$367
 $295
ESTIMATES AND CRITICAL ACCOUNTING POLICIESESTIMATES
The Partnership’s critical accounting policiesestimates are described in its Annual Report on Form 10-K filed with the SEC on February 17, 2023. No significant changes have not changedoccurred subsequent to those reported in Exhibit 99.1 to itsthe Form 8-K filed on October 2, 2017. The following10-K filing.
FORWARD-LOOKING STATEMENTS
This quarterly report contains various forward-looking statements and information is provided to supplement those disclosures specifically related to impairment of long-lived assets and goodwill.
Impairment of Long-Lived Assets and Goodwill.  During the three months ended June 30, 2017, Sunoco LP announced the sale of a majority of the assets in its retail reporting unit. Sunoco LP’s retail reporting unit includes 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, 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, management allocated a portion of the goodwill balance previously included in the Sunoco LP retail reporting unit to assets held for saleare based on the relative fair valuesour beliefs and those of the businessour General Partner, as well as assumptions made by and information currently available to be disposed of and the portion of the reporting unitus. These forward-looking statements are identified as any statement that will be retained in accordance with ASC 350-20-40-3. The amount of goodwill allocateddoes not relate strictly to assets held for sale was approximately $1.6 billion, and the amount of goodwill allocated to the remainder of the retail reporting unit, which is comprised of Sunoco LP’s ethanol plant, credit card processing services and franchise royalties, was approximately $188 million.
Once the retail reporting unit’s goodwill was allocated between assets held for sale and continuing operations, management performed goodwill impairment tests on both reporting units to which the goodwill balances were allocated. No goodwill impairment was identified for the $188 million goodwill balance that remained in the retail reporting unit. The result of the impairment test of the goodwill included within the assets held for sale initially indicated an impairment charge of $320 million, which was recognized during the three months ended June 30, 2017. Subsequent to June 30, 2017, management continued to evaluate the goodwill for impairment based on additional information on the fair value of the reporting unit, which resulted in an additional impairment of $44 million during the three months ended September 30, 2017. The key assumption in the impairment test for the goodwill balance classified as held for sale was the fair value of the disposal group, which was based on the assumed proceeds from the sale of those assets. The announced purchase and sale agreement includes the majority of the retail sites that have been classified as held for sale; thus, a key assumption in the goodwill impairment test was the assumed sales proceeds (less the related costs to sell) for the remainder of the sites, which represent approximately 15% of the total number of sites. Management is currently marketing the remaining sites for sale and utilized information from that sales process to develop the assumed sales proceeds for those sites. While management believes that the assumed sales proceeds for these remaining held-for-sale sites are

reasonable and likely to be obtained in a sale of those sites, an agreement has not been negotiated and therefore the ultimate outcome could be different than the assumptionhistorical or current facts. When used in the impairment test. Subsequentthis quarterly 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 the impairment of goodwill included within the assets held for sale, no further impairments of any other assets held for sale were deemed necessary as the remaining carrying value of the disposal group approximated the assumed proceeds from the sale of those assets less the cost to sell.
For goodwill included in the Alohaidentify forward-looking statements. Although we 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 the three months ended June 30, 2017. Management does notour General Partner believe that the goodwillexpectations 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;

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•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;
•the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
•the general level of petroleum product demand and the availability and price of NGL supplies;
•the level of domestic oil, natural gas and NGL production;
•the availability of imported oil, natural gas and NGLs;
•actions taken by foreign oil and gas producing nations;
•the political and economic stability of petroleum producing nations;
•the effect of weather conditions on demand for oil, natural gas and NGLs;
•availability of local, intrastate and interstate transportation systems;
•the continued ability to find and contract for new sources of natural gas supply;
•availability and marketing of competitive fuels;
•the impact of energy conservation efforts;
•energy efficiencies and technological trends;
•governmental regulation and taxation;
•changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
•competition from other midstream companies and interstate pipeline companies;
•loss of key personnel;
•loss of key natural gas producers or the providers of fractionation services;
•reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;
•the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;
•the nonpayment or nonperformance by our subsidiaries’ customers;
•regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems;
•risks associated with eitherthe construction of these reporting unitsnew pipelines and treating and processing facilities or the remaining goodwill of $188 million within the retail reporting unit is at significant risk of impairment,additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the goodwill will continueperformance 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 a noncontrolling interests, including risks related to management actions at such entities that our subsidiaries may not be subjectedable to annual goodwill impairment testingcontrol 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;

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•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 October 1.any forward-looking statements. When considering forward-looking statements, please review the risks described under “Part I - Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on February 17, 2023. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q 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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II - Item 7A included in ourthe Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016,2022 filed with the SEC on February 17, 2023, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2016.2022. Since December 31, 2016,2022, there have been no material changes to our primary market risk exposures or how those exposures are managed.
Commodity Price Risk
The following table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power and barrels for natural gas liquids, crude and refined products. Dollar amounts are presented in millions.

March 31, 2023December 31, 2022
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/Futures215 $— $— 145 $— $— 
Basis Swaps IFERC/NYMEX (1)
(49,423)(9)1 (39,563)54 3 
Power (Megawatt):
Forwards85,400 — — — 1 — 
Futures(289,918)2 1 (21,384)— — 
Options – Puts8,000 — — 119,200 — — 
Options – Calls(119,200)1 — — — — 
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX40,533 2 1 42,440 (41)4 
Swing Swaps IFERC(58,778)2 1 (202,815)63 7 
Fixed Swaps/Futures(10,225)2 4 (15,758)51 7 
Forward Physical Contracts532 5 1 2,423 8 1 
NGLs (MBbls) – Forwards/Swaps10,341 14 35 6,934 (41)63 
Crude (MBbls) – Forwards/Swaps(4,257)22 26 795 26 22 
Refined Products (MBbls) – Futures(2,401)(15)27 (3,547)(39)37 
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX(45,535)(1)1 (37,448)22 2 
Fixed Swaps/Futures(45,535)27 13 (37,448)58 17 
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
 September 30, 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 (MMBtu):           
Fixed Swaps/Futures1,297,500
 $—
 $—
 (682,500) $—
 $—
Basis Swaps IFERC/NYMEX (1)
(15,810,000) (4) —
 2,242,500
 (1) —
Options – Puts13,000,000
 —
 —
 —
 —
 —
Power (Megawatt):           
Forwards665,040
 1
 2
 391,880
 (1) 1
Futures(213,840) —
 1
 109,564
 —
 —
Options — Puts(280,800) 1
 2
 (50,400) —
 —
Options — Calls545,600
 —
 1
 186,400
 1
 —
Crude (Bbls):           
Futures(160,000) 1
 1
 (617,000) (4) 6
(Non-Trading)           
Natural Gas (MMBtu):           
Basis Swaps IFERC/NYMEX67,500
 (3) 2
 10,750,000
 2
 —
Swing Swaps IFERC91,897,500
 (2) —
 (5,662,500) (1) 1
Fixed Swaps/Futures(20,220,000) 1
 7
 (52,652,500) (27) 19
Forward Physical Contracts(140,937,993) 3
 43
 (22,492,489) 1
 —
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps(8,744,200) (48) 80
 (5,786,627) (40) 35
Refined Products (Bbls) — Futures(1,947,000) 1
 19
 (3,144,000) (21) 18
Corn (Bushels) — Futures650,000
 —
 —
 1,580,000
 —
 1
Fair Value Hedging Derivatives           
(Non-Trading)           
Natural Gas (MMBtu):           
Basis Swaps IFERC/NYMEX(41,102,500) 2
 —
 (36,370,000) 2
 1
Fixed Swaps/Futures(41,102,500) 5
 12
 (36,370,000) (26) 14
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair values of the commodity-related financial positions have been determined using independent third partythird-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the 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 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 portfolio may not change by 10% due to factors such as when the

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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 September 30, 2017,March 31, 2023, we and our subsidiaries had $10.47$4.29 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $105$43 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, (dollars in millions), none of which are designated as hedges for accounting purposes:purposes (dollar amounts presented in millions):
Term
Type(1)
Notional Amount Outstanding
March 31,
2023		December 31,
2022
July 2024(2)
Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate$400 $400 
    Notional Amount Outstanding
Term 
Type(1)
 September 30, 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 SOFR.
(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.
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 interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $237$80 million as of September 30, 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 flows of $19 million.March 31, 2023. 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.
The Partnership also has outstanding Series A Preferred Units with aggregate liquidation preference of $950 million, for which distributions are based on a floating rate beginning February 15, 2023. A hypothetical change of 100 basis points in interest rates for the Series A Preferred Units would result in a net change in preferred unit distributions of $10 million annually.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Under the supervision and with the participation of senior management, including the President (“PrincipalCo-Chief Executive Officer”)Officers (Co-Principal Executive Officers) and the Chief Financial Officer (“Principal(Principal Financial Officer”)Officer) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the PrincipalCo-Principal Executive OfficerOfficers and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2017March 31, 2023 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the PrincipalCo-Principal Executive OfficerOfficers and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal controls, other than those discussed above,control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended September 30, 2017March 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal controlscontrol over financial reporting.

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PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see our Annual Report on Form 10-K forfiled with the year ended December 31, 2016SEC on February 17, 2023 and Note 11 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated10 in “Item 1. Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries includedStatements” in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2017.March 31, 2023.

The EPA has brought aAdditionally, we have received notices of violations and potential fines under various federal, court action against SPLPstate and Mid-Valley for violationslocal provisions relating to the discharge of materials into the environment or protection of the Clean Water Act (“CWA”). The United States’ complaint allegesenvironment. While we believe that SPLP and Mid-Valley violated Sections 311(b)(7)(A) and 301(a)even if any one or more of the CWA when, during three separate releases, pipelines operated by SPLP and owned by SPLPfollowing environmental proceedings were decided against us, it would not be material to our financial position, results of operations or Mid-Valleycash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings reasonably could result in monetary sanctions in excess of $0.3 million.
On June 29, 2022, near Henderson, Tennessee, a Mid Valley Pipeline Company discharged oil. See 33 U.S.C. §§ 1311(a)LLC (“Mid Valley”) mowing contractor struck an exposed section of the 22-inch diameter Hornsby to Denver line segment while mowing. The brush cutter mowing implement cut open the pipeline and 1321(b)(7)(A). In particular, the three releases at issue occurred (1) on February 23, 2013, in Tyler County, Texas, when a reported 550released an estimated 4,345 barrels of crude oil into the surrounding area. Approximately 3,343 barrels of crude oil were discharged; (2) on October 13, 2014,recovered during initial remediation activities with the remaining volume contained within the materials removed and disposed of in Caddo Parish, Louisiana, when a reported 4,509 barrelsaccordance with applicable environmental laws and regulations. Corrective action is being completed pursuant to the Tennessee DEC’s Division of oil were discharged; and (3) on January 20, 2015, in Grant County, Oklahoma, when a reported 40 barrels of oil were discharged.  Potential finesRemediation - Voluntary Action Program (“VAP”). No injuries resulted from the DOJ are $7 million and from the State of Louisiana are approximately $1 million. The Partnership is currently in discussions to resolve these matters.
Mont Belvieuincident. Mid Valley received a Notice of Enforcement (“NOE”)Federal Interest regarding the incident and has also supplied PHMSA with an Agreed Orderinformation as requested. No other government agency action has occurred at this time. Mid Valley has submitted a draft closure report to the TDEC and received comments from the Texas Commissionagency. The comments were addressed and submitted in the final report on Environmental Quality and has a pending settlementApril 28, 2023, for $0.01 million.  The NOE was forclosure under the two violations.
Energy Transfer Company Field Services, LLC received a settlement agreement and a stipulatedVAP. We are awaiting final compliance orderinvoicing from the New Mexicofederal agencies (United States Environmental Department (“NMED”) on October 12, 2017 for allegations of violations of New Mexico air regulationsProtection Agency and United States Fish and Wildlife Service) and their consultants related to Jal #3 facilities. This order is a combination of Notice of Violation REG-0569-1402-R1 and Notice of Violation REG-0569-1601. The alleged violations occurred during the periods of March 24, 2014 through September 30, 2014 and Septemberincident.
Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II - Item 1 2016 through December 31, 2016. The settlement includes a civil penalty in the amount of $0.4 million and a supplement environmental project in the amount of $0.8 million.
Energy Transfer Company Field Services, LLC received a settlement offer from the NMED on June 6, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. The alleged violation occurredinclude any reportable legal proceeding (i) that has been terminated during the period of January 1, 2017 through September 11, 2017. The NMED is offering to settlecovered by this report, (ii) that became a reportable event during the violations with a civil penalty of $0.6 million.
On July 14, 2017, Sunoco LP’s subsidiary Aloha Petroleum, Ltd. (“Aloha”) received a Notice of Violation and Order (“NOVO”) from the Hawaii Department of Health (“DOH”) relating to alleged leak detection and reporting deficiencies at Aloha’s AIM Diamond Head facility in Honolulu, Hawaii with proposed civil penalties of $0.2 million. Aloha is in discussions with the DOH regarding the NOVO. The timingperiod covered by this report, or outcome of this matter cannot reasonably be determined at this time however, the Partnership does not expect(iii) for which there to behas been a material impact ondevelopment during the period covered by this report.
For additional information required in this Item, see disclosure under the headings “Litigation and Contingencies” and “Environmental Matters” in Note 10 to our business or results of operations.consolidated financial statements in “Item 1. Financial Statements”, which information is incorporated by reference into this Item.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors described in “PartPart I, — Item 1A. Risk Factors” of our1A in the Partnership’s Annual Report on Form 10-KForm10-K for the year ended December 31, 2016 or from2022 filed with the risk factors described in “Part II — Item 1A. Risk Factors” of our Quarterly ReportSEC on Form 10-Q for the quarter ended March 31, 2017.February 17, 2023.
ITEM 6. EXHIBITS

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The exhibits listed belowon the following exhibit index are filed or furnished, as indicated, as part of this report:
Exhibit NumberDescription
12.1*
Computation of Ratio of Earnings to Fixed Charges.
3.1
31.1*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
Certificate of Amendment of Certificate of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed October 19, 2018)
3.3
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)
3.4
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)
3.5
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)
3.6
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)
3.7
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)
3.8
Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated March 8, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed March 9, 2016)
3.9
Amendment No. 6 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated October 19, 2018 (incorporated by reference to Exhibit 3.9 of Form 10-Q (File No. 1-32740) filed November 8, 2018)
3.10
Amendment No. 7 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated August 6, 2019 (incorporated by reference to Exhibit 3.10 of Form 10-Q (File No. 1-32740) filed August 8, 2019)
3.11
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 3.1 of Form 8-K (File No. 1-32740) filed April 1, 2021)
3.12
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)
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)
31.1*
Certification of PresidentCo-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002
31.2*
31.2*Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.3*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.2002
32.1**
Certification of PresidentCo-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002
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 of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002
101.INS*101*XBRL Instance DocumentInteractive 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; (iv) our Consolidated Statements of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements
101.SCH*104Cover Page Interactive Data File (formatted as inline XBRL Taxonomy Extension Schema Documentand contained in Exhibit 101)
101.CAL**XBRL Taxonomy Calculation Linkbase DocumentFiled herewith
101.DEF***XBRL Taxonomy Extension Definitions DocumentFurnished herewith
101.LAB*XBRL Taxonomy Label Linkbase Document
101.PRE*XBRL Taxonomy Presentation Linkbase Document
*Filed herewith.
**Furnished herewith.



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SIGNATURE
Pursuant to the requirements 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.LP
By:LE GP, LLC, its General Partnergeneral partner
Date:November 7, 2017May 4, 2023By:/s/ Thomas E. LongA. Troy Sturrock
Thomas E. LongA. Troy Sturrock
Group Chief FinancialSenior Vice President, Controller and Principal Accounting Officer (duly
authorized to sign on behalf of the registrant)



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