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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20212022
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
et-20220930_g1.jpg
ENERGY TRANSFER LP
(Exact name of registrant as specified in its charter)
Delaware 30-0108820
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(Address of principal executive offices) (zip code)
(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 every Interactive Data File required to be submitted 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 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¨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 October 29, 2021,28, 2022, the registrant had 2,705,855,1723,088,475,132 Common Units outstanding.


TableTable of Contents
FORM 10-Q
ENERGY TRANSFER LP AND SUBSIDIARIES
TABLE OF CONTENTS

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Definitions
References to the “Partnership” or “ET”“Energy Transfer” refer to Energy Transfer LP. In addition, the following is a list of certain acronyms and terms used throughout this document:
/dper day
AOCIaccumulated other comprehensive income (loss)
BBtubillion British thermal units
CitrusCitrus, LLC, a 50/50 joint venture which owns FGT
Dakota AccessDakota Access, LLC, a non-wholly-owned subsidiary of Energy Transfer
EnableEnable Midstream Partners, LP, a Delaware limited partnership
Energy Transfer CanadaEnergy Transfer Canada ULC, a less than wholly-ownednon-wholly-owned subsidiary of ETEnergy Transfer until its sale in August 2022
Energy Transfer R&MEnergy Transfer (R&M), LLC (formerly Sunoco (R&M), LLC)
ETEnergy 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, and Series G Preferred Units (all originally issued by ETO and exchanged for preferred units issued by ET on April 1, 2021), as well as the Series H Preferred Units issued by ET in June 2021
ETC TigerETC Tiger Pipeline, LLC, a wholly-owned subsidiary of ET,Energy Transfer, which owns the Tiger Pipeline
ETC SunocoETC Sunoco Holdings LLC (formerly Sunoco, Inc.), a wholly-owned subsidiary of Energy Transfer
ETOEnergy Transfer Operating, L.P., formerly a non-wholly-owned subsidiary of Energy Transfer until its merger into the Partnership in April 2021
Exchange ActSecurities Exchange Act of 1934, as amended
ExplorerExplorer Pipeline Company
ETOEnergy Transfer Operating, L.P.
Exchange ActSecurities Exchange Act of 1934
FEPFayetteville Express Pipeline LLC
FERCFederal Energy Regulatory Commission
FGTFlorida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus
GAAPaccounting principles generally accepted in the United States of America
General PartnerLE GP, LLC, the general partner of Energy Transfer
HFOTCOHouston Fuel Oil Terminal Company, a wholly-owned subsidiary of ET,Energy Transfer, which owns the Houston Terminal
LE GPIFERCLE GP, LLC, the general partner of ETInside FERC’s Gas Market Report
LIBORLondon Interbank Offered Rate
MBblsthousand barrels
MEPMidcontinent Express Pipeline LLC
MMcfmillion cubic feet
MTBEmethyl tertiary butyl ether
NGLnatural gas liquid, such as propane, butane and natural gasoline
NYMEXNew York Mercantile Exchange
OSHAFederal Occupational Safety and Health Act
OTCover-the-counter
PanhandlePanhandle Eastern Pipe Line Company, LP, a wholly-owned subsidiary of ETEnergy Transfer
RegencyRegency Energy Partners LP
RoverRover Pipeline LLC, a non-wholly-owned subsidiary of Energy Transfer
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SECSecurities and Exchange Commission
Series A Preferred Units6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
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Series B Preferred Units6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series C Preferred Units7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series D Preferred Units7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series E Preferred Units7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series F Preferred Units6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series G Preferred Units7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series H Preferred Units6.500% Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
SCOOPSouth Central Oklahoma Oil Province
Sunoco Logistics OperationsSunoco Logistics Partners Operations L.P, a wholly-owned subsidiary of ET
SOFRSecured overnight financing rate
SPLPSunoco Pipeline L.P., a wholly-owned subsidiary of Energy Transfer
TranswesternTranswestern Pipeline Company, LLC, a wholly-owned subsidiary of ETEnergy Transfer
TrunklineTrunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle
USACUSA Compression Partners, LP, a publicly traded partnership and consolidated subsidiary of ET
USAC Preferred UnitsUSAC Series A preferred unitsEnergy Transfer
White CliffsWhite Cliffs Pipeline, L.L.C.

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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
(unaudited)
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
ASSETSASSETSASSETS
Current assets:Current assets:Current assets:
Cash and cash equivalentsCash and cash equivalents$313 $367 Cash and cash equivalents$326 $336 
Accounts receivable, netAccounts receivable, net6,437 3,875 Accounts receivable, net8,587 7,654 
Accounts receivable from related companiesAccounts receivable from related companies63 79 Accounts receivable from related companies92 54 
InventoriesInventories1,811 1,739 Inventories2,490 2,014 
Income taxes receivableIncome taxes receivable42 35 Income taxes receivable65 32 
Derivative assetsDerivative assets57 Derivative assets19 10 
Other current assetsOther current assets326 213 Other current assets580 437 
Total current assetsTotal current assets9,049 6,317 Total current assets12,159 10,537 
Property, plant and equipmentProperty, plant and equipment95,775 94,115 Property, plant and equipment105,040 103,991 
Accumulated depreciation and depletionAccumulated depreciation and depletion(21,504)(19,008)Accumulated depreciation and depletion(24,779)(22,384)
74,271 75,107 
Property, plant and equipment, netProperty, plant and equipment, net80,261 81,607 
Investments in unconsolidated affiliatesInvestments in unconsolidated affiliates2,958 3,060 Investments in unconsolidated affiliates2,869 2,947 
Lease right-of-use assets, netLease right-of-use assets, net829 866 Lease right-of-use assets, net815 838 
Other non-current assets, netOther non-current assets, net1,722 1,657 Other non-current assets, net1,573 1,645 
Intangible assets, netIntangible assets, net5,474 5,746 Intangible assets, net5,505 5,856 
GoodwillGoodwill2,395 2,391 Goodwill2,553 2,533 
Total assetsTotal assets$96,698 $95,144 Total assets$105,735 $105,963 
The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Dollars in million)
(unaudited)
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
LIABILITIES AND EQUITYLIABILITIES AND EQUITYLIABILITIES AND EQUITY
Current liabilities:Current liabilities:Current liabilities:
Accounts payableAccounts payable$5,707 $2,809 Accounts payable$7,514 $6,834 
Accounts payable to related companiesAccounts payable to related companies— 27 Accounts payable to related companies— 
Derivative liabilitiesDerivative liabilities205 238 Derivative liabilities60 203 
Operating lease current liabilitiesOperating lease current liabilities46 53 Operating lease current liabilities43 47 
Accrued and other current liabilitiesAccrued and other current liabilities3,198 2,775 Accrued and other current liabilities3,615 3,071 
Current maturities of long-term debtCurrent maturities of long-term debt678 21 Current maturities of long-term debt680 
Total current liabilitiesTotal current liabilities9,834 5,923 Total current liabilities11,243 10,835 
Long-term debt, less current maturitiesLong-term debt, less current maturities44,793 51,417 Long-term debt, less current maturities47,413 49,022 
Non-current derivative liabilitiesNon-current derivative liabilities187 237 Non-current derivative liabilities33 193 
Non-current operating lease liabilitiesNon-current operating lease liabilities799 837 Non-current operating lease liabilities794 814 
Deferred income taxesDeferred income taxes3,683 3,428 Deferred income taxes3,661 3,648 
Other non-current liabilitiesOther non-current liabilities1,270 1,152 Other non-current liabilities1,530 1,323 
Commitments and contingenciesCommitments and contingencies00Commitments and contingencies
Redeemable noncontrolling interestsRedeemable noncontrolling interests783 762 Redeemable noncontrolling interests493 783 
Equity:Equity:Equity:
Limited Partners:Limited Partners:Limited Partners:
Preferred UnitholdersPreferred Unitholders5,671 — Preferred Unitholders6,077 6,051 
Common UnitholdersCommon Unitholders21,726 18,531 Common Unitholders26,725 25,230 
General PartnerGeneral Partner(5)(8)General Partner(3)(4)
Accumulated other comprehensive incomeAccumulated other comprehensive income19 Accumulated other comprehensive income32 23 
Total partners’ capitalTotal partners’ capital27,411 18,529 Total partners’ capital32,831 31,300 
Noncontrolling interestsNoncontrolling interests7,938 12,859 Noncontrolling interests7,737 8,045 
Total equityTotal equity35,349 31,388 Total equity40,568 39,345 
Total liabilities and equityTotal liabilities and equity$96,698 $95,144 Total liabilities and equity$105,735 $105,963 
The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
(unaudited)
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020202120202022202120222021
REVENUES:REVENUES:REVENUES:
Refined product salesRefined product sales$4,810 $2,720 $12,737 $7,952 Refined product sales$6,647 $4,810 $20,043 $12,737 
Crude salesCrude sales4,021 2,298 10,920 7,170 Crude sales5,773 4,021 17,758 10,920 
NGL salesNGL sales4,005 1,808 10,275 4,751 NGL sales4,823 4,005 15,828 10,275 
Gathering, transportation and other feesGathering, transportation and other fees2,276 2,283 6,797 6,805 Gathering, transportation and other fees2,830 2,276 8,288 6,797 
Natural gas salesNatural gas sales1,376 681 7,507 1,783 Natural gas sales2,648 1,376 6,830 7,507 
OtherOther176 165 524 459 Other218 176 628 524 
Total revenuesTotal revenues16,664 9,955 48,760 28,920 Total revenues22,939 16,664 69,375 48,760 
COSTS AND EXPENSES:COSTS AND EXPENSES:COSTS AND EXPENSES:
Cost of products soldCost of products sold13,188 6,376 35,641 18,784 Cost of products sold18,516 13,188 56,169 35,641 
Operating expensesOperating expenses898 773 2,585 2,422 Operating expenses973 898 2,982 2,585 
Depreciation, depletion and amortizationDepreciation, depletion and amortization943 912 2,837 2,715 Depreciation, depletion and amortization1,030 943 3,104 2,837 
Selling, general and administrativeSelling, general and administrative198 176 583 555 Selling, general and administrative361 198 802 583 
Impairment losses— 1,474 11 2,803 
Impairment losses and otherImpairment losses and other86 — 386 11 
Total costs and expensesTotal costs and expenses15,227 9,711 41,657 27,279 Total costs and expenses20,966 15,227 63,443 41,657 
OPERATING INCOMEOPERATING INCOME1,437 244 7,103 1,641 OPERATING INCOME1,973 1,437 5,932 7,103 
OTHER INCOME (EXPENSE):OTHER INCOME (EXPENSE):OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalizedInterest expense, net of interest capitalized(558)(569)(1,713)(1,750)Interest expense, net of interest capitalized(577)(558)(1,714)(1,713)
Equity in earnings (losses) of unconsolidated affiliates71 (32)191 46 
Impairment of investment in an unconsolidated affiliate— (129)— (129)
Equity in earnings of unconsolidated affiliatesEquity in earnings of unconsolidated affiliates68 71 186 191 
Losses on extinguishments of debtLosses on extinguishments of debt— — (8)(62)Losses on extinguishments of debt— — — (8)
Gains (losses) on interest rate derivatives55 72 (277)
Gains on interest rate derivativesGains on interest rate derivatives60 303 72 
Other, netOther, net33 71 45 Other, net(120)33 (117)45 
INCOME (LOSS) BEFORE INCOME TAX EXPENSE984 (360)5,690 (525)
INCOME BEFORE INCOME TAX EXPENSEINCOME BEFORE INCOME TAX EXPENSE1,404 984 4,590 5,690 
Income tax expenseIncome tax expense77 41 234 168 Income tax expense82 77 159 234 
NET INCOME (LOSS)907 (401)5,456 (693)
NET INCOMENET INCOME1,322 907 4,431 5,456 
Less: Net income attributable to noncontrolling interestsLess: Net income attributable to noncontrolling interests260 242 870 427 Less: Net income attributable to noncontrolling interests304 260 793 870 
Less: Net income attributable to redeemable noncontrolling interestsLess: Net income attributable to redeemable noncontrolling interests12 12 37 37 Less: Net income attributable to redeemable noncontrolling interests12 12 37 37 
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS635 (655)4,549 (1,157)
General Partner’s interest in net income (loss)— (1)
NET INCOME ATTRIBUTABLE TO PARTNERSNET INCOME ATTRIBUTABLE TO PARTNERS1,006 635 3,601 4,549 
General Partner’s interest in net incomeGeneral Partner’s interest in net income
Preferred Unitholders’ interest in net incomePreferred Unitholders’ interest in net income99 — 185 — Preferred Unitholders’ interest in net income106 99 317 185 
Limited Partners’ interest in net income (loss)$535 $(655)$4,359 $(1,156)
Common Unitholders’ interest in net incomeCommon Unitholders’ interest in net income$899 $535 $3,281 $4,359 
NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
NET INCOME PER COMMON UNIT:NET INCOME PER COMMON UNIT:
BasicBasic$0.20 $(0.24)$1.61 $(0.43)Basic$0.29 $0.20 $1.06 $1.61 
DilutedDiluted$0.20 $(0.24)$1.60 $(0.43)Diluted$0.29 $0.20 $1.06 $1.60 
The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
(unaudited)
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020202120202022202120222021
Net income (loss)$907 $(401)$5,456 $(693)
Net incomeNet income$1,322 $907 $4,431 $5,456 
Other comprehensive income (loss), net of tax:Other comprehensive income (loss), net of tax:Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securitiesChange in value of available-for-sale securitiesChange in value of available-for-sale securities(4)(13)
Actuarial gain related to pension and other postretirement benefit plansActuarial gain related to pension and other postretirement benefit plans15 Actuarial gain related to pension and other postretirement benefit plans— 
Foreign currency translation adjustmentsForeign currency translation adjustments(21)18 (16)Foreign currency translation adjustments13 (21)(6)
Change in other comprehensive income (loss) from unconsolidated affiliates(15)
Change in other comprehensive income from unconsolidated affiliatesChange in other comprehensive income from unconsolidated affiliates24 
(17)26 15 (13)15 (17)12 15 
Comprehensive income (loss)890 (375)5,471 (706)
Comprehensive incomeComprehensive income1,337 890 4,443 5,471 
Less: Comprehensive income attributable to noncontrolling interestsLess: Comprehensive income attributable to noncontrolling interests250 251 872 407 Less: Comprehensive income attributable to noncontrolling interests307 250 787 872 
Less: Comprehensive income attributable to redeemable noncontrolling interestsLess: Comprehensive income attributable to redeemable noncontrolling interests12 12 37 37 Less: Comprehensive income attributable to redeemable noncontrolling interests12 12 37 37 
Comprehensive income (loss) attributable to partners$628 $(638)$4,562 $(1,150)
Comprehensive income attributable to partnersComprehensive income attributable to partners$1,018 $628 $3,619 $4,562 
The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
(unaudited)
Common UnitholdersPreferred UnitholdersGeneral PartnerAOCINoncontrolling InterestsTotalCommon UnitholdersPreferred UnitholdersGeneral PartnerAOCINoncontrolling InterestsTotal
Balance, December 31, 2020$18,531 $— $(8)$$12,859 $31,388 
Balance, December 31, 2021Balance, December 31, 2021$25,230 $6,051 $(4)$23 $8,045 $39,345 
Distributions to partnersDistributions to partners(406)— — — — (406)Distributions to partners(528)(80)— — — (608)
Distributions to noncontrolling interestsDistributions to noncontrolling interests— — — — (406)(406)Distributions to noncontrolling interests— — — — (307)(307)
Capital contributions from noncontrolling interestsCapital contributions from noncontrolling interests— — — — 20 20 Capital contributions from noncontrolling interests— — — — 373 373 
Other comprehensive income, net of taxOther comprehensive income, net of tax— — — Other comprehensive income, net of tax— — — 20 25 
Other, netOther, net18 — — — 21 Other, net17 — — — 10 27 
Net income, excluding amounts attributable to redeemable noncontrolling interestsNet income, excluding amounts attributable to redeemable noncontrolling interests3,285 — — 341 3,629 Net income, excluding amounts attributable to redeemable noncontrolling interests1,162 106 — 205 1,474 
Balance, March 31, 202121,428 — (5)12,823 34,254 
Preferred units converted in Rollup Mergers— 4,768 — — (4,768)— 
Balance, March 31, 2022Balance, March 31, 202225,881 6,077 (3)43 8,331 40,329 
Distributions to partnersDistributions to partners(403)(88)(1)— — (492)Distributions to partners(603)(131)(1)— — (735)
Distributions to noncontrolling interestsDistributions to noncontrolling interests— — — — (354)(354)Distributions to noncontrolling interests— — — — (446)(446)
Units issued— 889 — — — 889 
Capital contributions from noncontrolling interests— — — — 43 43 
Other comprehensive income, net of tax— — — 18 24 
Other, net15 (1)— — 16 
Net income, excluding amounts attributable to redeemable noncontrolling interests539 86 — 269 895 
Balance, June 30, 202121,579 5,654 (5)26 8,021 35,275 
Distributions to partners(404)(80)(1)— — (485)
Distributions to noncontrolling interests0— — — (389)(389)
Capital contributions from noncontrolling interestsCapital contributions from noncontrolling interests— — — — 51 51 Capital contributions from noncontrolling interests— — — — 24 24 
Other comprehensive loss, net of taxOther comprehensive loss, net of tax— — — (7)(10)(17)Other comprehensive loss, net of tax— — — (14)(14)(28)
Other, netOther, net16 (2)— — 19 Other, net— — — 11 
Net income, excluding amounts attributable to redeemable noncontrolling interestsNet income, excluding amounts attributable to redeemable noncontrolling interests535 99 — 260 895 Net income, excluding amounts attributable to redeemable noncontrolling interests1,220 105 — 284 1,610 
Balance, September 30, 2021$21,726 $5,671 $(5)$19 $7,938 $35,349 
Balance, June 30, 2022Balance, June 30, 202226,507 6,051 (3)29 8,181 40,765 
Distributions to partnersDistributions to partners(694)(80)(1)— — (775)
Distributions to noncontrolling interestsDistributions to noncontrolling interests— — — (424)(424)
Capital contributions from noncontrolling interestsCapital contributions from noncontrolling interests— — — — 
Energy Transfer Canada saleEnergy Transfer Canada sale— — — (9)(337)(346)
Other comprehensive income, net of taxOther comprehensive income, net of tax— — — 12 15 
Other, netOther, net13 — — — 16 
Net income, excluding amounts attributable to redeemable noncontrolling interestsNet income, excluding amounts attributable to redeemable noncontrolling interests899 106 — 304 1,310 
Balance, September 30, 2022Balance, September 30, 2022$26,725 $6,077 $(3)$32 $7,737 $40,568 










The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY (continued)
(Dollars in millions)
(unaudited)
Common UnitholdersGeneral PartnerAOCINoncontrolling InterestsTotalCommon UnitholdersPreferred UnitholdersGeneral PartnerAOCINoncontrolling InterestsTotal
Balance, December 31, 2019$21,935 $(4)$(11)$12,018 $33,938 
Distributions to partners(1,591)(1)— — (1,592)
Distributions to noncontrolling interests— — — (444)(444)
Subsidiary units issued— — — 1,580 1,580 
Capital contributions from noncontrolling interests— — — 95 95 
Other comprehensive loss, net of tax— — (48)(38)(86)
Other, net22 — — (7)15 
Net loss, excluding amounts attributable to redeemable noncontrolling interests(854)(1)— (121)(976)
Balance, March 31, 202019,512 (6)(59)13,083 32,530 
Distributions to partners(1)— — 
Distributions to noncontrolling interests— — — (408)(408)
Capital contributions from noncontrolling interests— — — 83 83 
Other comprehensive income, net of tax— — 38 47 
Other, net(31)— — (27)
Net income, excluding amounts attributable to redeemable noncontrolling interests353 — — 306 659 
Balance, June 30, 202019,843 (7)(21)13,077 32,892 
Balance, December 31, 2020Balance, December 31, 2020$18,531 $— $(8)$$12,859 $31,388 
Distributions to partnersDistributions to partners(812)(1)— — (813)Distributions to partners(406)— — — — (406)
Distributions to noncontrolling interestsDistributions to noncontrolling interests— — — (430)(430)Distributions to noncontrolling interests— — — — (406)(406)
Capital contributions from noncontrolling interestsCapital contributions from noncontrolling interests— — — 25 25 Capital contributions from noncontrolling interests— — — — 20 20 
Other comprehensive income, net of taxOther comprehensive income, net of tax— — 17 26 Other comprehensive income, net of tax— — — 
Other, netOther, net47 — — (43)Other, net18 — — — 21 
Net income (loss), excluding amounts attributable to redeemable noncontrolling interests(655)— — 242 (413)
Balance, September 30, 2020$18,423 $(8)$(4)$12,880 $31,291 
Net income, excluding amounts attributable to redeemable noncontrolling interestsNet income, excluding amounts attributable to redeemable noncontrolling interests3,285 — — 341 3,629 
Balance, March 31, 2021Balance, March 31, 202121,428 — (5)12,823 34,254 
Preferred units converted in Rollup MergersPreferred units converted in Rollup Mergers— 4,768 — — (4,768)— 
Distributions to partnersDistributions to partners(403)(88)(1)— — (492)
Distributions to noncontrolling interestsDistributions to noncontrolling interests— — — — (354)(354)
Units issuedUnits issued— 889 — — — 889 
Capital contributions from noncontrolling interestsCapital contributions from noncontrolling interests— — — — 43 43 
Other comprehensive income, net of taxOther comprehensive income, net of tax— — — 18 24 
Other, netOther, net15 (1)— — 16 
Net income, excluding amounts attributable to redeemable noncontrolling interestsNet income, excluding amounts attributable to redeemable noncontrolling interests539 86 — 269 895 
Balance, June 30, 2021Balance, June 30, 202121,579 5,654 (5)26 8,021 35,275 
Distributions to partnersDistributions to partners(404)(80)(1)— — (485)
Distributions to noncontrolling interestsDistributions to noncontrolling interests— — — — (389)(389)
Capital contributions from noncontrolling interestsCapital contributions from noncontrolling interests— — — — 51 51 
Other comprehensive loss, net of taxOther comprehensive loss, net of tax— — — (7)(10)(17)
Other, netOther, net16 (2)— — 19 
Net income, excluding amounts attributable to redeemable noncontrolling interestsNet income, excluding amounts attributable to redeemable noncontrolling interests535 99 — 260 895 
Balance, September 30, 2021Balance, September 30, 2021$21,726 $5,671 $(5)$19 $7,938 $35,349 
The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
(unaudited)
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2021202020222021
OPERATING ACTIVITIES:OPERATING ACTIVITIES:OPERATING ACTIVITIES:
Net income (loss)$5,456 $(693)
Reconciliation of net income (loss) to net cash provided by operating activities:
Net incomeNet income$4,431 $5,456 
Reconciliation of net income to net cash provided by operating activities:Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortizationDepreciation, depletion and amortization2,837 2,715 Depreciation, depletion and amortization3,104 2,837 
Deferred income taxesDeferred income taxes199 159 Deferred income taxes158 199 
Inventory valuation adjustmentsInventory valuation adjustments(168)126 Inventory valuation adjustments(81)(168)
Non-cash compensation expenseNon-cash compensation expense81 93 Non-cash compensation expense88 81 
Impairment lossesImpairment losses11 2,803 Impairment losses386 11 
Impairment of investment in an unconsolidated affiliate— 129 
Losses on extinguishments of debtLosses on extinguishments of debt62 Losses on extinguishments of debt— 
Distributions on unvested awardsDistributions on unvested awards(19)(33)Distributions on unvested awards(37)(19)
Equity in earnings of unconsolidated affiliatesEquity in earnings of unconsolidated affiliates(191)(46)Equity in earnings of unconsolidated affiliates(186)(191)
Distributions from unconsolidated affiliatesDistributions from unconsolidated affiliates226 176 Distributions from unconsolidated affiliates182 226 
Other non-cashOther non-cash13 (130)Other non-cash(120)13 
Net change in operating assets and liabilities, net of effects of acquisitions970 94 
Net change in operating assets and liabilities, net of effects of acquisitions and divestituresNet change in operating assets and liabilities, net of effects of acquisitions and divestitures(212)970 
Net cash provided by operating activitiesNet cash provided by operating activities9,423 5,455 Net cash provided by operating activities7,713 9,423 
INVESTING ACTIVITIES:INVESTING ACTIVITIES:INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash receivedCash paid for acquisitions, net of cash received(1,062)— 
Capital expenditures, excluding allowance for equity funds used during constructionCapital expenditures, excluding allowance for equity funds used during construction(2,046)(4,030)Capital expenditures, excluding allowance for equity funds used during construction(2,493)(2,046)
Contributions in aid of construction costsContributions in aid of construction costs29 61 Contributions in aid of construction costs50 29 
Contributions to unconsolidated affiliatesContributions to unconsolidated affiliates(4)(37)Contributions to unconsolidated affiliates— (4)
Distributions from unconsolidated affiliates in excess of cumulative earningsDistributions from unconsolidated affiliates in excess of cumulative earnings76 144 Distributions from unconsolidated affiliates in excess of cumulative earnings66 76 
Proceeds from sale of Energy Transfer Canada interestProceeds from sale of Energy Transfer Canada interest302 — 
Proceeds from sales of other assetsProceeds from sales of other assets38 10 Proceeds from sales of other assets60 38 
Other— (9)
Net cash used in investing activitiesNet cash used in investing activities(1,907)(3,861)Net cash used in investing activities(3,077)(1,907)
FINANCING ACTIVITIES:FINANCING ACTIVITIES:FINANCING ACTIVITIES:
Proceeds from borrowingsProceeds from borrowings11,839 20,651 Proceeds from borrowings19,400 11,839 
Repayments of debtRepayments of debt(17,836)(20,293)Repayments of debt(21,110)(17,836)
Preferred Units issued for cash889 — 
Subsidiary units issued for cash— 1,580 
Preferred units issued for cashPreferred units issued for cash— 889 
Capital contributions from noncontrolling interestsCapital contributions from noncontrolling interests114 203 Capital contributions from noncontrolling interests404 114 
Distributions to partnersDistributions to partners(1,383)(2,397)Distributions to partners(2,118)(1,383)
Distributions to noncontrolling interestsDistributions to noncontrolling interests(1,149)(1,282)Distributions to noncontrolling interests(1,177)(1,149)
Distributions to redeemable noncontrolling interest(37)(37)
Distributions to redeemable noncontrolling interestsDistributions to redeemable noncontrolling interests(37)(37)
Debt issuance costsDebt issuance costs(3)(53)Debt issuance costs(9)(3)
Other, netOther, net(4)18 Other, net(4)
Net cash used in financing activitiesNet cash used in financing activities(7,570)(1,610)Net cash used in financing activities(4,646)(7,570)
Decrease in cash and cash equivalentsDecrease in cash and cash equivalents(54)(16)Decrease in cash and cash equivalents(10)(54)
Cash and cash equivalents, beginning of periodCash and cash equivalents, beginning of period367 291 Cash and cash equivalents, beginning of period336 367 
Cash and cash equivalents, end of periodCash and cash equivalents, end of period$313 $275 Cash and cash equivalents, end of period$326 $313 
The accompanying notes are an integral part of these consolidated financial statements.
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ENERGY TRANSFER 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
Organization
The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ET”“Energy Transfer”).
On April 1, 2021, ET, ETO and certain of ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). In connection with the Rollup Mergers, Sunoco Logistics Operations merged with and into ETO, with ETO surviving, and immediately thereafter, ETO merged with and into ET, with ET surviving. The impacts of the Rollup Mergers also included the following:
All of ETO’s long-term debt was assumed by ET, as more fully described in Note 7.
Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created ET preferred unit. A description of the ET Preferred Units is included in Note 9.
Each of ETO’s issued and outstanding Class K, Class L, Class M and Class N units, all of which were held by ETP Holdco Corporation, a wholly-owned subsidiary of ETO, were converted into an aggregate 675,625,000 newly created Class B Units representing limited partner interests in ET.
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, 2020,2021, filed with the SEC on February 19, 2021.18, 2022. 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.
The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.
Our subsidiaries also own varying undivided The Partnership owns the general partner interest, incentive distribution rights and 28.5 million common units of Sunoco LP, and the general partner interests in certain pipelines. Ownershipand 46.1 million common units of these pipelines has been structured as 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.USAC.
Certain prior period amounts have been reclassified to conform to the current period presentation. These 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 requires 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.
2.ACQUISITIONS AND RELATEDDIVESTITURE TRANSACTIONS
Pending EnableWoodford Express Acquisition
On February 16, 2021,September 13, 2022, Energy Transfer completed the acquisition of 100% of the membership interests in Woodford Express, LLC, which owns a mid-continent gas gathering and processing system, for approximately $485 million in cash consideration. The system, which is located in the heart of the SCOOP play, has 450 MMcf/d of cryogenic gas processing and treating capacity and over 200 miles of gathering lines, which are connected to Energy Transfer’s pipeline network. Woodford Express, LLC repaid an aggregate principal amount of $292 million of its revolving credit facility and term loan on the closing date of the acquisition, which amount is included in the total consideration.The purchase price has primarily been allocated to working capital and property, plant and equipment in the preliminary purchase price allocation reflected in the Partnership’s consolidated balance sheet at September 30, 2022.
Energy Transfer Canada Sale
In August 2022, the Partnership entered into a definitive merger agreementcompleted the previously announced sale of its 51% interest in Energy Transfer Canada. The sale resulted in cash proceeds to acquire Enable. UnderEnergy Transfer of C$390 million (US$302 million).
Energy Transfer Canada’s assets and operations were included in the termsPartnership’s all other segment until August 2022. Energy Transfer Canada did not meet the criteria to be reflected as discontinued operations in the Partnership’s consolidated statement of operations. Based on the anticipated proceeds upon signing of the mergershare purchase agreement Enable’s common unitholders will receive 0.8595in February 2022, during the three months ended March 31, 2022, the Partnership recorded a write-down on Energy Transfer Canada’s assets of an ET common unit in exchange for each Enable common unit. In addition, each outstanding Enable preferred unit will be exchanged for 0.0265$300 million, of a Series G Preferredwhich $164 million was allocated to noncontrolling interests and $136 million was

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Unit, and ET will make a $10reflected in net income attributable to partners. Upon the completion of the sale in August 2022, the Partnership recorded an $85 million cash paymentloss on deconsolidation.
Spindletop Assets Purchase
In March 2022, the Partnership purchased the membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for Enable’s general partner. In Mayapproximately $325 million.
Enable Acquisition
On December 2, 2021, the Partnership completed the acquisition of Enable common unitholders voted to approve the merger. The transaction is subject(the “Enable Acquisition”). As of November 3, 2022, there have been no material changes to the satisfaction of customary closing conditions, including Hart-Scott-Rodino Act (“HSR”) clearance.
The Federal Trade Commission (“FTC”) has issued requestspreliminary purchase price allocation disclosed in our Annual Report on Form 10-K for additional information and documentary material (the “Second Request”). The effect of the Second Request is to extend the waiting period imposed by the HSR Act until 30 days after the Partnership and Enable have certified substantial complianceyear ended December 31, 2021, filed with the Second Request, unless that period is extended voluntarily or terminated sooner bySEC on February 18, 2022.
Sunoco LP Acquisition
On April 1, 2022, Sunoco LP completed the FTC. We continueacquisition of a transmix processing and terminal facility in Huntington, Indiana for $252 million, net of cash acquired, of which $98 million was allocated to believe that the FTC will grant clearance of the transaction,intangible assets, $20 million to goodwill, $73 million to property, plant and we remain fully committedequipment and $76 million to closing the Enable merger under the terms of the merger agreement. We expect to close the transaction in the fourth quarter of 2021.working capital.
3.CASH AND CASH EQUIVALENTS
Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of September 30, 20212022 or December 31, 2020.2021.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities, net of effects of acquisitions, included in cash flows from operating activities is comprised as follows:
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2021202020222021
Accounts receivableAccounts receivable$(2,562)$1,307 Accounts receivable$(999)$(2,562)
Accounts receivable from related companiesAccounts receivable from related companies16 (258)Accounts receivable from related companies17 16 
InventoriesInventories96 (298)Inventories(287)96 
Other current assetsOther current assets(127)108 Other current assets(176)(127)
Other non-current assets, netOther non-current assets, net(57)(26)Other non-current assets, net106 (57)
Accounts payableAccounts payable2,917 (1,354)Accounts payable599 2,917 
Accounts payable to related companiesAccounts payable to related companies(31)370 Accounts payable to related companies(31)
Accrued and other current liabilitiesAccrued and other current liabilities711 127 Accrued and other current liabilities585 711 
Other non-current liabilitiesOther non-current liabilities138 (5)Other non-current liabilities254 138 
Derivative assets and liabilities, netDerivative assets and liabilities, net(131)123 Derivative assets and liabilities, net(312)(131)
Net change in operating assets and liabilities, net of effects of acquisitions$970 $94 
Net change in operating assets and liabilities, net of effects of acquisitions and divestituresNet change in operating assets and liabilities, net of effects of acquisitions and divestitures$(212)$970 

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Non-cash investing and financing activities were as follows:
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2021202020222021
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expendituresAccrued capital expenditures$385 $684 Accrued capital expenditures$454 $385 
Lease assets obtained in exchange for new lease liabilitiesLease assets obtained in exchange for new lease liabilities10 130 Lease assets obtained in exchange for new lease liabilities37 10 
Distribution reinvestmentDistribution reinvestment24 72 Distribution reinvestment42 24 
4.INVENTORIES
Inventories consist principallyconsisted of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.following:
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September 30,
2022
December 31,
2021
Natural gas, NGLs and refined products$1,910 $1,259 
Crude oil166 328 
Spare parts and other414 427 
Total inventories$2,490 $2,014 
Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As of September 30, 20212022 and December 31, 2020,2021, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $143$40 million and $311$121 million, respectively, andrespectively. The fuel inventory replacement cost was $6 million higher than the fuel inventory carrying value equaled or exceeded its replacement cost.balance as of September 30, 2022. For the three and nine months ended September 30, 20212022 and 2020,2021, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory.
September 30,
2021
December 31,
2020
Natural gas, NGLs and refined products(1)
$1,238 $1,013 
Crude oil160 287 
Spare parts and other413 439 
Total inventories$1,811 $1,739 
(1)Due For the three months ended September 30, 2022 and September 30, 2021, the Partnership’s cost of products sold included unfavorable and favorable inventory adjustments of $40 million and $9 million, respectively, related to changes in fuel prices, Sunoco LP recorded an inventory adjustment on the value of its fuel inventory of $168 million forLP’s LIFO inventory. For the nine months ended September 30, 2021.
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets2022 and 2021, the Partnership’s cost of products sold in our consolidated statementsincluded favorable inventory adjustments of operations.$81 million and $168 million, respectively, related to Sunoco LP’s LIFO inventory.
5.FAIR VALUE MEASURES
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 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 nine months ended September 30, 2021,2022, no transfers were made between any levels within the fair value hierarchy.

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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, 20212022 and December 31, 20202021 based on inputs used to derive their fair values:
Fair Value Measurements at
September 30, 2021
Fair Value Measurements at
September 30, 2022
Fair Value TotalLevel 1Level 2Fair Value TotalLevel 1Level 2
Assets:Assets:Assets:
Commodity derivatives:Commodity derivatives:Commodity derivatives:
Natural Gas:Natural Gas:Natural Gas:
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX$14 $14 $— Basis Swaps IFERC/NYMEX$23 $23 $— 
Swing Swaps IFERCSwing Swaps IFERC11 11 — Swing Swaps IFERC27 27 — 
Fixed Swaps/FuturesFixed Swaps/Futures— Fixed Swaps/Futures50 50 — 
Forward Physical ContractsForward Physical Contracts— Forward Physical Contracts— 
Power:Power:Power:
ForwardsForwards36 — 36 Forwards63 — 63 
FuturesFutures— Futures— 
Options – Calls— 
NGLs – Forwards/SwapsNGLs – Forwards/Swaps384 384 — NGLs – Forwards/Swaps669 669 — 
Refined Products – FuturesRefined Products – Futures— Refined Products – Futures11 11 — 
Crude – Forwards/SwapsCrude – Forwards/Swaps569 569 — Crude – Forwards/Swaps26 26 — 
Total commodity derivativesTotal commodity derivatives1,034 994 40 Total commodity derivatives883 812 71 
Other non-current assetsOther non-current assets37 24 13 Other non-current assets31 20 11 
Total assetsTotal assets$1,071 $1,018 $53 Total assets$914 $832 $82 
Liabilities:Liabilities:Liabilities:
Interest rate derivativesInterest rate derivatives$(376)$— $(376)Interest rate derivatives$(84)$— $(84)
Commodity derivatives:Commodity derivatives:Commodity derivatives:
Natural Gas:Natural Gas:Natural Gas:
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX(5)(5)— Basis Swaps IFERC/NYMEX(11)(11)— 
Swing Swaps IFERCSwing Swaps IFERC(7)(7)— Swing Swaps IFERC(2)(2)— 
Fixed Swaps/FuturesFixed Swaps/Futures(78)(78)— Fixed Swaps/Futures(63)(63)— 
Forward Physical ContractsForward Physical Contracts(1)— (1)Forward Physical Contracts(2)— (2)
Power:Power:Power:
ForwardsForwards(21)— (21)Forwards(57)— (57)
FuturesFutures(11)(11)— Futures(9)(9)— 
Options – CallsOptions – Calls(2)(2)— Options – Calls(1)(1)— 
NGLs – Forwards/SwapsNGLs – Forwards/Swaps(364)(364)— NGLs – Forwards/Swaps(493)(493)— 
Refined Products – FuturesRefined Products – Futures(10)(10)— Refined Products – Futures(8)(8)— 
Crude – Forwards/SwapsCrude – Forwards/Swaps(582)(582)— Crude – Forwards/Swaps(14)(14)— 
Total commodity derivativesTotal commodity derivatives(1,081)(1,059)(22)Total commodity derivatives(660)(601)(59)
Total liabilitiesTotal liabilities$(1,457)$(1,059)$(398)Total liabilities$(744)$(601)$(143)

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Fair Value Measurements at
December 31, 2020
Fair Value Measurements at
December 31, 2021
Fair Value TotalLevel 1Level 2Fair Value TotalLevel 1Level 2
Assets:Assets:Assets:
Commodity derivatives:Commodity derivatives:Commodity derivatives:
Natural Gas:Natural Gas:Natural Gas:
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX$12 $12 $— Basis Swaps IFERC/NYMEX$$$— 
Swing Swaps IFERCSwing Swaps IFERC— Swing Swaps IFERC38 38 — 
Fixed Swaps/FuturesFixed Swaps/Futures13 13 — Fixed Swaps/Futures26 26 — 
Forward Physical ContractsForward Physical Contracts— Forward Physical Contracts— 
Power:Power:Power:
ForwardsForwards— Forwards17 — 17 
FuturesFutures— Futures— 
Options – Calls— 
NGLs – Forwards/SwapsNGLs – Forwards/Swaps127 127 — NGLs – Forwards/Swaps152 152 — 
Refined Products – FuturesRefined Products – Futures— Refined Products – Futures— 
Crude – Forwards/SwapsCrude – Forwards/Swaps16 16 — 
Total commodity derivativesTotal commodity derivatives168 158 10 Total commodity derivatives272 248 24 
Other non-current assetsOther non-current assets34 22 12 Other non-current assets39 26 13 
Total assetsTotal assets$202 $180 $22 Total assets$311 $274 $37 
Liabilities:Liabilities:Liabilities:
Interest rate derivativesInterest rate derivatives$(448)$— $(448)Interest rate derivatives$(387)$— $(387)
Commodity derivatives:Commodity derivatives:Commodity derivatives:
Natural Gas:Natural Gas:Natural Gas:
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX(11)(11)— Basis Swaps IFERC/NYMEX(10)(10)— 
Swing Swaps IFERCSwing Swaps IFERC(3)— (3)Swing Swaps IFERC(6)(6)— 
Fixed Swaps/FuturesFixed Swaps/Futures(13)(13)— Fixed Swaps/Futures(9)(9)— 
Forward Physical ContractsForward Physical Contracts(1)— (1)Forward Physical Contracts(6)— (6)
Power:Power:Power:
ForwardsForwards(15)— (15)
FuturesFutures(3)(3)— Futures(4)(4)— 
NGLs – Forwards/SwapsNGLs – Forwards/Swaps(227)(227)— NGLs – Forwards/Swaps(140)(140)— 
Refined Products – FuturesRefined Products – Futures(11)(11)— Refined Products – Futures(18)(18)— 
Crude – Forwards/SwapsCrude – Forwards/Swaps(3)(3)— 
Total commodity derivativesTotal commodity derivatives(269)(265)(4)Total commodity derivatives(211)(190)(21)
Total liabilitiesTotal liabilities$(717)$(265)$(452)Total liabilities$(598)$(190)$(408)
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, 20212022 were $51.26$43.27 billion and $45.47$47.42 billion, respectively. As of December 31, 2020,2021, the aggregate fair value and carrying amount of our consolidated debt obligations were $56.21$54.97 billion and $51.44$49.70 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.

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6.NET INCOME (LOSS) PER LIMITED PARTNERCOMMON UNIT
A reconciliation of income or loss and weighted average units used in computing basic and diluted income (loss) per common unit is as follows:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
Net income (loss)$907 $(401)$5,456 $(693)
Less: Net income attributable to noncontrolling interests260 242 870 427 
Less: Net income attributable to redeemable noncontrolling interests12 12 37 37 
Net income (loss), net of noncontrolling interests635 (655)4,549 (1,157)
Less: General Partner’s interest in income (loss)— (1)
    Less: Preferred Unitholders’ interest in income99 — 185 — 
Income (loss) available to Limited Partners$535 $(655)$4,359 $(1,156)
Basic Income (Loss) per Limited Partner Unit:
Weighted average limited partner units2,705.2 2,696.6 2,704.0 2,694.4 
Basic income (loss) per Limited Partner unit$0.20 $(0.24)$1.61 $(0.43)
Diluted Income (Loss) per Limited Partner Unit:
Income (loss) available to Limited Partners$535 $(655)$4,359 $(1,156)
Dilutive effect of equity-based compensation of subsidiaries (1)
— — 
Diluted income (loss) available to Limited Partners$534 $(655)$4,357 $(1,156)
Weighted average limited partner units2,705.2 2,696.6 2,704.0 2,694.4 
Dilutive effect of unvested unit awards (1)
15.4 — 14.4 — 
Weighted average limited partner units, assuming dilutive effect of unvested unit awards2,720.6 2,696.6 2,718.4 2,694.4 
Diluted income (loss) per Limited Partner unit$0.20 $(0.24)$1.60 $(0.43)
Three Months Ended
September 30,
Nine Months Ended
September 30,
2022202120222021
Net income$1,322 $907 $4,431 $5,456 
Less: Net income attributable to noncontrolling interests304 260 793 870 
Less: Net income attributable to redeemable noncontrolling interests12 12 37 37 
Net income, net of noncontrolling interests1,006 635 3,601 4,549 
Less: General Partner’s interest in net income
    Less: Preferred Unitholders’ interest in net income106 99 317 185 
Common Unitholders’ interest in net income$899 $535 $3,281 $4,359 
Basic Income per Common Unit:
Weighted average common units3,087.6 2,705.2 3,085.6 2,704.0 
Basic income per common unit$0.29 $0.20 $1.06 $1.61 
Diluted Income per Common Unit:
Common Unitholders’ interest in net income$899 $535 $3,281 $4,359 
Dilutive effect of equity-based compensation of subsidiaries (1)
— 
Diluted income attributable to Common Unitholders$899 $534 $3,279 $4,357 
Weighted average common units3,087.6 2,705.2 3,085.6 2,704.0 
Dilutive effect of unvested restricted unit awards (1)
21.0 15.4 20.8 14.4 
Weighted average common units, assuming dilutive effect of unvested restricted unit awards3,108.6 2,720.6 3,106.4 2,718.4 
Diluted income per common unit$0.29 $0.20 $1.06 $1.60 
(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.
7.DEBT OBLIGATIONS
Senior Notes
In connection withFebruary 2022, the Rollup Mergers on April 1, 2021, as discussed in Note 1, ET entered into various supplemental indentures and assumed all the obligations of ETO under the respective indentures and credit agreements.
During the first quarter of 2021, ETOPartnership redeemed its $600$300 million aggregate principal amount of 4.40% senior notesits 4.65% Senior Notes due February 2022 using proceeds from its Five-Year Credit Facility (defined below).
In April 1, 2021 and its $8002022, Dakota Access redeemed $650 million aggregate principal amount of 4.65% senior notesits 3.625% Senior Notes due June 1, 2021,April 2022 using proceeds from contributions made by its members. The Partnership indirectly owns 36.4% of the Five-Year Credit Facility.ownership interests in Dakota Access.
DuringIn August 2022, the third quarter of 2021, ET issuedPartnership exercised its par call notices to redeem in full its $1.0 billion aggregate principal amount of 5.2% senior notes due February 1, 2022,option and $900fully redeemed $700 million aggregate principal amount of 5.875% senior notesits 5.00% Senior Notes due March 1, 2022. The Partnership expects to redeem both series of senior notes during the fourth quarter of 2021, utilizingOctober 2022 with proceeds from its Five-Year Credit Facility.
On October 20, 2021, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2030 (the “2030 Notes”). Sunoco LP used the proceeds from the private offering to fund a tender offer and repurchase all of its senior notes due 2026.
Credit Facilities and Commercial Paper
Term Loan
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO’s obligations in respect of its term loan credit agreement (the “Term Loan”) and Sunoco Logistics Operations was released as a guarantor in respect of the Term Loan. The Partnership’s Term Loan provides for a $2.00 billion three-year term loan credit facility.
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During the second quarter of 2021, the Partnership repaid $1.5 billion on the Term Loan in part through proceeds from its Series H Preferred Unit issuance. During the third quarter of 2021, the Partnership repaid the remaining $500 million balance and terminated the Term Loan.
Five-Year Credit Facility
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO’s obligations in respect of itsThe Partnership’s revolving credit facility (the “Five-Year Credit Facility”) and Sunoco Logistics Operations was released as a guarantor in respect of the Five-Year Credit Facility. The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2024.April 11, 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00$7.00 billion under certain conditions.
As of September 30, 2021,2022, the Five-Year Credit Facility had $599 million$2.65 billion of outstanding borrowings, of which $590$825 million consisted of commercial paper. The amount available for future borrowings was $4.37$2.32 billion, after accounting for outstanding letters of credit in the amount of $31$38 million. The weighted average interest rate on the total amount outstanding as of September 30, 20212022 was 0.43%4.29%.
364-Day Facility

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Table of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO’s obligations in respect of its 364-day revolving credit facility (the “364-Day Facility”) and Sunoco Logistics Operations was released as a guarantor in respect of the 364-Day Facility. The Partnership’s 364-Day Facility allows for unsecured borrowings up to $1.00 billion and matures on November 26, 2021. As of September 30, 2021, the 364-Day Facility had no outstanding borrowings.Contents
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of September 30, 2021, the2022, Sunoco LP Credit FacilityLP’s credit facility had $250$704 million of outstanding borrowings and $6$7 million in standby letters of credit and, as amended in April 2022, matures in July 2023.April 2027. The amount available for future borrowings at September 30, 20212022 was $1.24 billion.$789 million. The weighted average interest rate on the total amount outstanding as of September 30, 20212022 was 2.09%5.11%.
USAC Credit Facility
USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity. As of September 30, 2021, USAC2022, USAC’s credit facility had $506$618 million of outstanding borrowings under the USAC Credit Facility.and no outstanding letters of credit. As of September 30, 2021,2022, USAC had $1.09 billion$982 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $114$287 million. The weighted average interest rate on the total amount outstanding as of September 30, 20212022 was 2.96%5.54%.
Energy Transfer Canada Credit Facilities
Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$276 million at the September 30, 2021 exchange rate) senior secured term loan facility (the “Energy Transfer Canada Term Loan A”), a C$525 million (US$414 million at the September 30, 2021 exchange rate) senior secured revolving credit facility (the “Energy Transfer Canada Revolving Credit Facility”), and a C$300 million (US$237 million at the September 30, 2021 exchange rate) senior secured construction loan facility (the “KAPS Facility”). The Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$197 million at the September 30, 2021 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders. As of September 30, 2021, the Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility had outstanding borrowings of C$320 million and C$103 million, respectively (US$252 million and US$81 million, respectively, at the September 30, 2021 exchange rate). As of September 30, 2021, the KAPS Facility had outstanding borrowings of C$65 million (US$51 million at the September 30, 2021 exchange rate).
Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our debt agreements as of September 30, 2021.2022. For the quarter ended September 30, 2021,2022, our leverage ratio, as calculated pursuant to the covenant related to our revolving credit facility, was 3.15x.3.35x.
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8.REDEEMABLE NONCONTROLLING INTERESTS
Certain redeemable noncontrolling interests in the Partnership’s subsidiaries arewere reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of September 30, 20212022 included a balance of $477 million related to the USAC Preferred Units described belowSeries A preferred units and a balance of $16 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. As of December 31, 2021, redeemable noncontrolling interests included a balance of $477 million related to the USAC Series A preferred units, a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, as of September 30, 2021, redeemable noncontrolling interests includedPartnership and a balance of $291 million related to Energy Transfer Canada preferred shares.
USAC Preferred Units
As of September 30, 2021, USAC had 500,000 USAC Preferred Units issued and outstanding. The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units are convertible into USAC common units at the election of the holders. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by April 2023, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, beginning April 2028, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and USAC may elect to pay up to 50% of such redemption amount in USAC common units.
Energy Transfer Canada Redeemable Preferred Stock
Energy Transfer Canada has 300,000preferred shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at Energy Transfer Canada’s option at a redemption price of C$1,100 (US$867 atwere deconsolidated in connection with the September 30, 2021 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of Energy Transfer Canada. The preferred stock is convertible to Energy Transfer Canada common sharessale in the event of an initial public offering by Energy Transfer Canada.
Dividends on the preferred stock were payable in-kind through the quarter ended June 30, 2021. The dividends paid-in-kind increased the liquidation preference such that, as of September 30, 2021, the preferred stock was convertible into 367,521 shares.
For the quarter ended September 30, 2021, Energy Transfer Canada declared cash dividends of C$8 million (US$6 million at the September 30, 2021 exchange rate) on the preferred stock that will be paid in the fourth quarter of 2021.August 2022.
9.EQUITY
ETEnergy Transfer Common Units
The changeChanges in ETEnergy Transfer common units during the nine months ended September 30, 2021 was2022 were as follows:
Number of Units
Number of common units at December 31, 202020212,702.43,082.5 
Common units issued in connection withunder the distribution reinvestment plan2.73.8 
Common units vested under equity incentive plans and other0.72.1 
Number of common units at September 30, 202120222,705.83,088.4 
ETEnergy Transfer Repurchase Program
During the nine months ended September 30, 2021, ET2022, Energy Transfer did not repurchase any ETof its common units under its current buyback program. As of September 30, 2021, $9112022, $880 million remained available to repurchase under the current program.
ETEnergy Transfer Distribution Reinvestment Program
During the nine months ended September 30, 2021,2022, distributions of $24$42 million were reinvested under the distribution reinvestment program. As of September 30, 2021,2022, a total of 1813 million ETEnergy Transfer common units remained available to be issued under the existing registration statement in connection with the distribution reinvestment program.
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Cash Distributions on ETEnergy Transfer Common Units
Distributions declared and/or paid with respect to ETEnergy Transfer common units subsequent to December 31, 20202021 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 20202021February 8, 20212022February 19, 202118, 2022$0.15250.1750 
March 31, 20212022May 11, 20219, 2022May 19, 202120220.15250.2000 
June 30, 20212022August 6, 20218, 2022August 19, 202120220.15250.2300 
September 30, 20212022November 5, 20214, 2022November 19, 202121, 20220.15250.2650 
The Partnership’s distribution on its common units with respect to the quarter ended March 31, 2020 was declared on March 31, 2020 and accrued as of that date. For the three months ended March 31, 2020, the consolidated statement of equity reflected distributions to common unitholders for two quarters. For the three months ended June 30, 2020, the amount reflected for distributions to common unitholders in the consolidated statements of equity reflected only the reinvestment of distributions paid in May 2020.
ET Preferred Units
Conversion of ETO Preferred Units to ETEnergy Transfer Preferred Units
In connection with the Rollup Mergersmerger of Energy Transfer, ETO, and certain of ETO’s subsidiaries (the “Rollup Mergers”) on April 1, 2021, as discusseddescribed in Note 1,the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021, all of ETO’s previously outstanding preferred units were converted to ETEnergy Transfer Preferred Units with identical distribution and redemption rights, as described under “Description of ET Preferred Units” below.
As of and prior to March 31, 2021, the ET Preferred Units were reflected as noncontrolling interests on the Partnership’s consolidated financial statements. Beginning April 1, 2021, the ET Preferred Units are reflected as limited partner interests in the Partnership’s consolidated financial statements.rights.
As of September 30, 2022 and December 31, 2021, ET’sEnergy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series 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, 1,100,0001,484,780 Series G Preferred Units and 900,000 Series H Preferred Units.
The following table summarizes changes in the ETEnergy Transfer Preferred Units:
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 15 27 15 106 
Balance, March 31, 2022943 547 440 434 786 504 1,515 908 6,077 
Distributions to partners— — (8)(9)(15)(16)(53)(30)(131)
Net income15 15 26 15 105 
Balance, June 30, 2022958 556 440 434 786 496 1,488 893 6,051 
Distributions to partners(30)(18)(8)(9)(15)— — — (80)
Net income15 15 27 15 106 
Balance, September 30, 2022$943 $547 $440 $434 $786 $504 $1,515 $908 $6,077 
Preferred Unitholders
Series ASeries BSeries CSeries DSeries ESeries FSeries GSeries HTotal
Balance, March 31, 2021$— $— $— $— $— $— $— $— $— 
Preferred units conversion943 547 440 434 786 504 1,114 — 4,768 
Units issued for cash— — — — — — — 889 889 
Distributions to partners— — (8)(9)(15)(17)(39)— (88)
Other, net— — — — — — — (1)(1)
Net income15 15 20 86 
Balance, June 30, 2021958 556 440 434 786 495 1,095 890 5,654 
Distributions to partners(30)(18)(8)(9)(15)— — — (80)
Other, net— — — — — — — (2)(2)
Net income15 15 20 15 99 
Balance, September 30, 2021$943 $547 $440 $434 $786 $503 $1,115 $903 $5,671 

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Cash Distributions on ETEnergy Transfer Preferred Units
Distributions declared on the ETEnergy Transfer Preferred Units were as follows:
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Period EndedRecord DatePayment Date
Series A (1)
Series B (1)
Series CSeries DSeries E
Series F (1)
Series G (1)
Series H (1)
March 31, 2021May 3, 2021May 17, 2021$— $— $0.4609 $0.4766 $0.4750 $33.75 $35.625 $— 
June 30, 2021August 2, 2021August 16, 202131.25 33.125 0.4609 0.4766 0.4750 — — — 
September 30, 2021November 1, 2021November 15, 2021— — 0.4609 0.4766 0.4750 33.75 35.625 27.08(2)
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, 2021February 1, 2022February 15, 2022$31.250 $33.125 $0.4609 $0.4766 $0.475 $— $— $— 
March 31, 2022May 2, 2022May 16, 2022— — 0.4609 0.4766 0.475 33.750 35.625 32.500 
June 30, 2022August 1, 2022August 15, 202231.250 33.125 0.4609 0.4766 0.475 — — — 
September 30, 2022November 1, 2022November 15, 2022— — 0.4609 0.4766 0.475 33.750 35.625 32.500
(1)Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.
(2)Represents initial prorated distribution.Noncontrolling Interests
Description of ETFor the three months ended March 31, 2021, noncontrolling interests included the ETO preferred units, which were converted into Energy Transfer Preferred Units
Following is a summary of the distribution and redemption rights associated on April 1, 2021 in connection with the ET Preferred Units:
Series A Preferred Units. DistributionsRollup Mergers, as described in the Partnership’s Annual Report on Form 10-K for the Series A Preferred Units will accrue and be cumulative to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. Distributions on the Series A Preferred Units will be payable semi-annually in arrears on the 15th day of February and August of each year. The Series A Preferred Units are redeemable at ET’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series B Preferred Units. Distributions on the Series B Preferred Units will accrue and be cumulative to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. Distributions on the Series B Preferred Units will be payable semi-annually in arrears on the 15th day of February and August of each year. The Series B Preferred Units are redeemable at ET’s option on or after February 15, 2028 at a redemption price of $1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series C Preferred Units. Distributions on the Series C Preferred Units will accrue and be cumulative to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. Distributions on the Series C Preferred Units will be payable quarterly in arrears on the 15th day of February, May, August and November of each year. The Series C Preferred Units are redeemable at ET’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series D Preferred Units. Distributions on the Series D Preferred Units will accrue and be cumulative to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. Distributions on the Series D Preferred Units will be payable quarterly in arrears on the 15th day of February, May, August and November of each year. The Series D Preferred Units are redeemable at ET’s option on or after August 15, 2023 at a redemption price of $25 per Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series E Preferred Units. Distributions on the Series E Preferred Units will accrue and be cumulative to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the Series E Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 5.161% per annum. Distributions on the Series E Preferred Units will be payable quarterly in arrears on the 15th day of February, May, August and November of each year. The Series E Preferred Units are redeemable at ET’s option on or after May 15, 2024 at a redemption price of $25 per Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series F Preferred Units. Distributions on the Series F Preferred Units will accrue and be cumulative to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the Series F Preferred Units will equal a percentage of the $1,000 liquidation preference equal
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to the five-year U.S. treasury rate plus a spread of 5.134% per annum. Distributions on the Series F Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series F Preferred Units are redeemable at ET’s option on or after May 15, 2025 at a redemption price of $1,000 per Series F Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series G Preferred Units. Distributions on the Series G Preferred Units will accrue and be cumulative to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Series G Preferred Units will equal a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. Distributions on the Series G Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series G Preferred Units are redeemable at ET’s option on or after May 15, 2030 at a redemption price of $1,000 per Series G Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series H Preferred Units. On June 15, 2021, the Partnership issued 900,000 Series H Preferred Units at a price to the public of $1,000 per unit. Distributions on the Series H Preferred Units will accrue and be cumulative to, but excluding, November 15, 2026, at a rate equal to 6.500% per annum of the $1,000 liquidation preference. On and after November 15, 2026 and each fifth anniversary thereafter, the distribution rate on the Series H Preferred Units will reset to be a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.694% per annum. Distributions on the Series H Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series H Preferred Units are redeemable at ET’s option during the three-month period prior to, and including, each distribution reset date at a redemption price of $1,000 per Series H Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Noncontrolling Interestsyear ended December 31, 2021.
The Partnership’s consolidated financial statements also include noncontrolling interests in Sunoco LP and USAC, both of which are publicly traded master limited partnerships, as well as other less-than-wholly-owned,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 (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter.
Sunoco LP Cash Distributions
Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 20202021 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 20202021February 8, 20212022February 19, 202118, 2022$0.8255 
March 31, 20212022May 11, 20219, 2022May 19, 202120220.8255 
June 30, 20212022August 6, 20218, 2022August 19, 202120220.8255 
September 30, 20212022November 5, 20214, 2022November 19, 202118, 20220.8255 
USAC Cash Distributions
Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 20202021 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 20202021January 25, 202124, 2022February 5, 20214, 2022$0.525 
March 31, 20212022April 26, 202125, 2022May 7, 20216, 20220.525 
June 30, 20212022July 26, 202125, 2022August 6, 20215, 20220.525 
September 30, 20212022October 25, 202124, 2022November 5, 20214, 20220.525 
USAC’s Warrant Exercise
As of December 31, 2021, USAC had outstanding two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. On April 27, 2022, the tranche of warrants with the right to purchase 5,000,000 common units with a strike price of $17.03 per common unit was exercised in full by the holders. The exercise of the warrants was net settled by USAC for 534,308 of its common units.
As of September 30, 2022, the tranche of Warrants with the right to purchase 10,000,000 common units with a strike price of $19.59 per common unit was outstanding and may be exercised by the holders at any time before April 2, 2028.
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Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
Available-for-sale securitiesAvailable-for-sale securities$23 $18 Available-for-sale securities$$19 
Foreign currency translation adjustmentForeign currency translation adjustment12 Foreign currency translation adjustment13 
Actuarial loss related to pensions and other postretirement benefits(1)(7)
Actuarial gains related to pensions and other postretirement benefitsActuarial gains related to pensions and other postretirement benefits12 
Investments in unconsolidated affiliates, netInvestments in unconsolidated affiliates, net(13)(14)Investments in unconsolidated affiliates, net13 (11)
Total AOCI, net of taxTotal AOCI, net of tax21 Total AOCI, net of tax32 26 
Amounts attributable to noncontrolling interestAmounts attributable to noncontrolling interest(2)Amounts attributable to noncontrolling interest— (3)
Total AOCI included in partners’ capital, net of taxTotal AOCI included in partners’ capital, net of tax$19 $Total AOCI included in partners’ capital, net of tax$32 $23 
10.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
Winter Storm Impacts
Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income and also affected the results of operations in certain segments. The recognition of the impacts of Winter Storm Uri during the nine months ended September 30, 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.
FERC Proceedings
Rover – FERC - Stoneman House
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million 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.
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, which are slated for argument on November 7, 2022, with decisions unlikely until 2023. 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 investigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the FERC 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 Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. The primary contractor (and one of

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the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.
Transwestern - FERC
On July 1, 2022, Transwestern filed a rate case pursuant to Section 4 of the Natural Gas Act. By order dated September 9, 2022, a procedural schedule was adopted in this proceeding, setting the Ordercommencement of the hearing for June 22, 2023.
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 (“NGA”)NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. 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. This matter remains pending before the FERC.
In May 2021, the FERC commenced an audit of Sunoco Pipeline LP (“SPLP”)SPLP for the period from January 1, 2018 to present to evaluate SPLP’s compliance with its FERC oil tariffs, the accounting requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s Form No. 6 including Page 700, reporting requirements. The audit is ongoing.
IRS Audit
The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service.
Commitments
In the normal course of business, our subsidiaries purchase, processEnergy Transfer purchases, processes and sellsells natural gas pursuant to long-term contracts and enter 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 the Partnership’s financial position or results of operations.
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon the 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 table below reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2021202020212020
ROW expense$18 $13 $33 $32 
Three Months Ended
September 30,
Nine Months Ended
September 30,
2022202120222021
ROW expense$16 $18 $44 $33 
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.

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We or our subsidiaries are a partyparties 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 September 30, 20212022 and December 31, 2020,2021, accruals of approximately $130$343 million and $101$144 million, respectively, were reflected on our consolidated balance sheets related to contingenciescontingent losses 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 $80$750 million.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The sections below also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed below, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.
Dakota Access Pipeline
On July 27, 2016, the 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”) that allowed Dakota Access to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“Court of Appeals”) which granted an administrative stay of the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals 1) granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, 2) denied a motion to stay 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
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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. On August 31, 2020, the USACE submitted a status report that indicated that it considered the presence of the 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 Tribes subsequently filed a motion seeking an injunction to stop the operation of the pipeline and both of the USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.

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On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the easement. In this 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 hear the case. Oppositions were filed by the Solicitor General (December 17, 2021) and the Tribes (December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.
The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the easement. At the request of the USACE, on February 9, 2021 the District Court granted a two-month continuance for the status conference until April 9, 2021. On April 9, 2021, the District Court granted Dakota Access’s request for the opportunity to file updates to its declarations supporting the opposition to injunctive relief and thereafter granted the Tribes’ request to file updates to their declarations supporting their position with respect to injunctive relief. Dakota Access and the Tribes filed their supplemental declarations on April 19, 2021 and April 26, 2021, respectively. On April 26, 2021, the District Court requested that USACE advise it by May 3, 2021 as to USACE’s current position, if it has one, with respect to the Motion. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. The USACE also advised the District Court that it expected that the EIS will be completed by March 2022. On May 21, 2021, the District Court denied the Plaintiffs’plaintiffs’ request for an injunction. The District Court further directed the parties to file a joint status report by June 11, 2021 concerning potential next steps in the litigation.
On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. The Court noted the availability of a motion to reopen the terminated proceedings if, for example, one of its earlier orders were violated. The Court also noted that should the Plaintiffs seek to challenge the forthcoming EIS, they would need to do so by filing a new complaint, and they could ask that it be assigned to the same Judge.
The pipeline continues to operate pending completion of the EIS. The USACE now estimates thatEnergy Transfer anticipates the draft EIS will be completecompleted and published by the endUSACE in the Spring of 2023, subject to additional delays by the USACE. The release of the draft EIS was paused following the SRST’s withdrawal as a cooperating agency on January 20, 2022. ETHowever, the pause has since been lifted and the USACE expects to release the draft EIS in the spring of 2023. Energy Transfer cannot determine when or how future lawsuits will be resolved or the impact they may have on the Dakota Access pipelines; however, ETEnergy 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 LLC’sMont Belvieu LP’s (“Lone Star”), now known as Energy Transfer GCMont Belvieu NGLs LLC,LP, facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and seek reimbursement for outstanding losses.
MTBE Litigation
ETC Sunoco Holdings LLC and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
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As of September 30, 2021,2022, Sunoco Defendants are defendants in 5four cases, including one case each initiated by the StatesState of Maryland, and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco, Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”)., 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

On June 10, 2015, Adrian Dieckman (“Dieckman” or “Plaintiff”), a purported Regency unitholder, filed a class action complaint related to the Regency-ETO merger (the “Regency Merger”) in the Court24

Table 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, ET, ETO, Energy Transfer Partners GP, L.P., and the members of Regency’s board of directors.Contents
The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. Plaintiff then filed an Amended Verified Class Action Complaint, which defendants moved to dismiss. The Court of Chancery granted in part and denied in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). The Court of Chancery later granted Plaintiff’s unopposed motion for class certification. Trial was held on December 10-16, 2019, and a post-trial hearing was held on May 6, 2020. On February 15, 2021, the Court of Chancery ruled in favor of the Regency Defendants on all claims at issue in this litigation, determined that the Regency Merger was fair and reasonable to Regency, and denied Plaintiff any relief.
On March 19, 2021, Plaintiff filed a notice of appeal, and oral argument was held on October 20, 2021. The Regency Defendants cannot predict the outcome of this appeal but intend to vigorously oppose it.
Litigation Filed By or Against Williams
In April and May 2016, the WilliamsThe William Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against ET,Energy Transfer, LE GP, LLC, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “ET“Energy Transfer Defendants”), alleging that ETEnergy Transfer Defendants breached their obligations under the ET-WilliamsEnergy Transfer-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that ETEnergy 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) issuing the Partnership’s seriesSeries A convertible preferred units (the “Issuance”), and (c) making allegedly untrue representations and warranties in the Merger Agreement.
After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETEnergy Transfer Defendants and issued a declaratory judgment that ETEnergy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not reach a decision regarding Williams’ claims related to the Issuance nor certain of the alleged untrue representations and warranties. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial.
In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a $410 million termination fee (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. ETEnergy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to ETEnergy Transfer for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause.
Trial was held regarding the parties’ amended claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court subsequently awarded Williams approximately $190 million in attorneys’ fees, expenses and pre-judgment interest.
On September 21, 2022, the Court entered a post-trial hearing was held on September 16, 2021. ETfinal judgment against the Energy Transfer Defendants cannot predict the outcome of the Williams Litigation nor can the ET Defendants predictin the amount of time and expense that will be required to resolveapproximately $601 million plus post-judgment interest at a rate of 3.5% per year. The Energy Transfer Defendants filed the Williams Litigation. ET Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.
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appeal of this matter on October 21, 2022.
Rover - State of Ohio
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“(together “the Ohio EPA”) filed suit against Rover and five other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. Briefing has concludedOn March 17, 2022, the Ohio Supreme Court reversed in part and oral argument was heldremanded 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 if its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. On October 2, 2022, the State of Ohio filed its Reply. Replies are due on January 26, 2021. The parties are awaiting a decision.November 4, 2022.
Revolution
On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries.
The Pennsylvania Office of Attorney General has(“PA AG”) commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident.

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On February 2, 2022, the PA AG issued a press release related to the Revolution pipeline, and released a Grand Jury Presentment and filed a criminal complaint against ETC Northeast Pipeline, LLC in Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania, with respect to nine misdemeanor charges related to various alleged violations of the Clean Streams Law associated with the construction of the Revolution pipeline.
On August 5, 2022, the PA AG held a press conference to announce that the matter had been resolved through an agreement whereby ETC Northeast Pipeline, LLC entered a plea of no contest to all charges. The scoperesolution also included terms that the company would pay a $22,500 fine to the Clean Water Fund at the Pennsylvania Department of these investigationsEnvironmental Protection, and jointly with SPLP to pay certain funds to support water quality improvement projects (see below). The plea agreement was entered by court on August 12, 2022, and the matter is not further known at this time.now closed.
Chester County, Pennsylvania Investigation
In December 2018, the former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines.
Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the prescribed time period.
In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.
On April 22, 2021, the Chester County DA filed a Complaint and Consent Decree in the Court of Common Pleas of Chester County, Pennsylvania constituting a settlement agreement between the Chester County DA and the Partnership. A status conference was held on May 10, 2021, and an Amended Consent Decree was filed on June 16, 2021, which has not yet beenwas approved and entered by the Court.Court on December 20, 2021. In accordance with the terms of the Amended Consent Decree, when the Mariner East 2/Mariner East 2X pipelines reached the point of mechanical completion in Chester County on March 23, 2022, the Amended Consent Decree terminated, which the Partnership communicated to the Chester County DA via letter on March 29, 2022. A Joint Motion for Termination of the Amended Consent Decree was filed on August 26, 2022.
Delaware County, Pennsylvania Investigation
On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the Pennsylvania Attorney General’s Office (the “AG”),PA AG, at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the PA AG served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. The Partnership has complied with the subpoena. On October 5, 2021, the PA AG held a press conference related to the Mariner East pipelines, released a Grand Jury Presentment and subsequently filed a criminal complaint against ETEnergy Transfer in the Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania with respect to 47 misdemeanor charges related to the discharge of industrial waste and pollution and one felony charge related to the failure to report information related to the discharges.
On August 5, 2022, the PA AG held a press conference to announce that the matter had been resolved through an agreement whereby SPLP entered a plea of no contest to 14 of the misdemeanor charges, with the remaining charges being dismissed. The Partnership will defend itself vigorously against these charges. On October 13, 2021,resolution also included terms that the AG announced that hecompany would pay a $35,000 fine to the Clean Water Fund at the Pennsylvania Department of Environmental Protection, and jointly with ETC Northeast Pipeline, LLC to resolve a parallel action by the PA AG’s office (see above), would establish a fund of $442,500 to create a Homeowner Well Water Supply Grievance Program and pay $10 million to support water quality improvement projects. The plea agreement was entered by the court on August 12, 2022, and the matter is running for Governor of Pennsylvania.now closed.
Shareholder Litigation Regarding Pennsylvania Pipeline Construction
FourVarious purported unitholders of ETEnergy Transfer have filed derivative actions against various past and current members of ET’sEnergy Transfer’s Board of Directors, LE GP, LLC, and ET,Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of ET’sEnergy Transfer’s limited partnership agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the

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construction of pipelines in Pennsylvania.Pennsylvania and Ohio. They also seek damages and changes to ET’sEnergy 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.); and 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.). The King action has been consolidated with the Bettiol action.
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Another purported unitholder of ET,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 ETEnergy Transfer and three of ET’sEnergy 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 ETEnergy 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 ET between February 25, 2017 and November 11, 2019.
On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer, Energy Transfer’s CFO Brad Whitehurst, and Messrs. Warren, Long, and McCrea. 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 Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of the Rover pipeline project.
On August 10, 2022, the Court appointed the New Mexico State Investment Council and Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey.
The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing; nor can the defendants 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 SPMTEnergy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged SPMTETMT 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, SPMTETMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. The matter has now beenwas fully briefed, and oral argument has beenwas set for November 15, 2021. SPMTHowever, 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

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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 is now engaging in asset discovery and is actively trying to collect on the judgment through garnishment proceedings. ETMT filed a request for an emergency stay of execution to the United States Supreme Court, which was denied on September 8, 2022. To stop the garnishment proceedings, on October 11, 2022, ETMT filed an Emergency Motion for Leave to Deposit Funds in the Court’s Registry in the amount of $161 million, 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. The Court heard this Motion on October 25, 2022, and ETMT is awaiting the Magistrate Judge’s issuance of the report and recommendation to the District Court.
ETMT cannot predict the outcome of the case, nor can SPMTETMT predict the amount of time and expense that will be required to resolve the appeal, but intends to vigorously appealappeal. A Petition for Writ of Certiorari was filed with the entiretyUnited States Supreme Court on April 28, 2022, seeking review of the Order.10th Circuit’s dismissal of ETMT’s appeal. The Supreme Court denied ETMT’s Petition on October 3, 2022. Despite the denial of its Petition for Writ of Certiorari, ETMT is still vigorously appealing the finality issues underlying the Order and has appealed the denial of the Motion to Modify to the 10th Circuit in an attempt to get a decision on finality. ETMT filed its opening brief with the 10th Circuit on September 13, 2022, and Plaintiff’s response was filed on October 13, 2022. ETMT’s reply brief is due on November 3, 2022.
Energy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.
On April 8, 2022, Energy Transfer LP (“Energy Transfer”) and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower,” and together with Culberson and Culberson Equity, “Defendants”). On October 1, 2018, ETC and Culberson entered into a Gas Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to require Energy Transfer to purchase their respective interests in Culberson for approximately $93 million. On April 8, 2022, Plaintiffs filed suit against Defendants asserting claims for declaratory judgment and breach of contract. Plaintiffs contend that Defendants 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 Defendants' put notice is void. Defendants have answered the lawsuit. 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, Defendants filed an application for a temporary restraining order, temporary injunction, and permanent injunction. The Court held a hearing on the application on April 28 and denied the injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation, to which Plaintiffs objected. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an appraisal process regarding the put price. An independent appraiser was appointed and issued his decision on October 15, 2022, concluding that the Put Price totals $93,064,891. Plaintiffs have consistently reiterated their objection to the appraisal process. 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 Massachusetts Department of Public Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March 2012. Subsequent to the merger, in

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2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending 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 reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50 percent) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA AG failed to take any further steps to prosecute its claims for nearly seven years. The 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 are now actively 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 privilege issue. On October 6, 2022, without even affording Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the procedural schedule. Accordingly, all previous deadlines (including the MA AG’s October 7, 2022, deadline to submit direct 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 expense that will be required to resolve these claims; however, Respondents will vigorously defend themselves against the MA AG’s claims.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on our 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.
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Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.

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certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
legacy sites related to Sunoco, Inc. are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.
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, 2021,2022, the Partnership had been named as a PRP at approximately 3334 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon the 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 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 require disclosure in our consolidated financial statements.
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
CurrentCurrent$44 $44 Current$46 $46 
Non-currentNon-current253 262 Non-current231 247 
Total environmental liabilitiesTotal environmental liabilities$297 $306 Total environmental liabilities$277 $293 
We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the nine months ended September 30, 20212022 and 2020,2021, the Partnership recorded $18$8 million and $22$18 million, respectively, of expenditures related to environmental cleanup programs.
Our pipeline operations are subject to regulation by the United States Department of TransportationDOT under PHMSA, pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
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Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements,

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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 termlong-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.
The following table summarizes the consolidated activity of our contract liabilities:
Contract Liabilities
Balance, December 31, 2021$459 
Additions815 
Revenue recognized(688)
Other(13)
Balance, September 30, 2022$573 
Balance, December 31, 2020$308309 
Additions611 
Revenue recognized(512)
Balance, September 30, 2021$407 
Balance, December 31, 2019$377 
Additions598 
Revenue recognized(614)
Balance, September 30, 2020$361408 
The balances of Sunoco LP’s contract assets were as follows:
September 30,
2021
December 31,
2020
Contract balances:
Contract assets$148 $121 
Accounts receivable from contracts with customers473 256 
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September 30,
2022
December 31,
2021
Contract balances:
Contract assets$182 $157 
Accounts receivable from contracts with customers631 463 
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

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performance obligation, the Partnership allocates the total expected 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 componentcomponents of the contracts are included in the table below.
As of September 30, 2021,2022, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $40.13 billion, and the$37.96 billion. The Partnership expects to recognize this amount as revenue within the time bands illustrated below:
Years Ending December 31,
2021
(remainder)20222023ThereafterTotal
Revenue expected to be recognized on contracts with customers existing as of September 30, 2021$1,662 $6,010 $5,504 $26,950 $40,126 
Years Ending December 31,
2022
(remainder)20232024ThereafterTotal
Revenue expected to be recognized on contracts with customers existing as of September 30, 2022$1,659 $6,609 $5,618 $24,077 $37,963 
12.DERIVATIVE ASSETS AND LIABILITIES
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales in our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be
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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:
September 30, 2021December 31, 2020September 30, 2022December 31, 2021
Notional VolumeMaturityNotional VolumeMaturityNotional VolumeMaturityNotional VolumeMaturity
Mark-to-Market DerivativesMark-to-Market DerivativesMark-to-Market Derivatives
(Trading)(Trading)(Trading)
Natural Gas (BBtu):Natural Gas (BBtu):Natural Gas (BBtu):
Fixed Swaps/FuturesFixed Swaps/Futures763 2022-2023585 2022-2023
Basis Swaps IFERC/NYMEX (1)
Basis Swaps IFERC/NYMEX (1)
(81,963)2021-2022(44,225)2021-2022
Basis Swaps IFERC/NYMEX (1)
73,363 2022-2023(66,665)2022
Fixed Swaps/Futures475 2021-20231,603 2021-2022
Power (Megawatt):Power (Megawatt):Power (Megawatt):
ForwardsForwards712,400 2021-20291,392,400 2021-2029Forwards455,200 2023-2029653,000 2023-2029
FuturesFutures(640,800)2021-202218,706 2021-2022Futures(281,905)2022-2023(604,920)2022-2023
Options – PutsOptions – Puts290,400 2021-2022519,071 2021Options – Puts119,200 2022-2023(7,859)2022
Options – CallsOptions – Calls36,704 2021-20222,343,293 2021Options – Calls(67,200)2022-2023(30,932)2022
(Non-Trading)(Non-Trading)(Non-Trading)
Natural Gas (BBtu):Natural Gas (BBtu):Natural Gas (BBtu):
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX(8,893)2021-2022(29,173)2021-2022Basis Swaps IFERC/NYMEX36,443 2022-20246,738 2022-2023
Swing Swaps IFERCSwing Swaps IFERC(48,675)2021-202211,208 2021Swing Swaps IFERC(217,515)2022-2024(106,333)2022-2023
Fixed Swaps/FuturesFixed Swaps/Futures(45,588)2021-2023(53,575)2021-2022Fixed Swaps/Futures(31,383)2022-2024(63,898)2022-2023
Forward Physical ContractsForward Physical Contracts(10,071)2021(11,861)2021Forward Physical Contracts(27,603)2022-2024(5,950)2023
NGLs (MBbls) – Forwards/SwapsNGLs (MBbls) – Forwards/Swaps2,785 2021-2023(5,840)2021-2022NGLs (MBbls) – Forwards/Swaps4,832 2022-20258,493 2022-2024
Crude (MBbls) – Forwards/SwapsCrude (MBbls) – Forwards/Swaps3,732 2022-20233,672 2022-2023
Refined Products (MBbls) – FuturesRefined Products (MBbls) – Futures(3,272)2021-2023(2,765)2021Refined Products (MBbls) – Futures(2,604)2022-2024(3,349)2022-2023
Crude (MBbls) – Forwards/Swaps1,693 2021-2022— 
Fair Value Hedging DerivativesFair Value Hedging DerivativesFair Value Hedging Derivatives
(Non-Trading)(Non-Trading)(Non-Trading)
Natural Gas (BBtu):Natural Gas (BBtu):Natural Gas (BBtu):
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX(21,255)2021(30,113)2021Basis Swaps IFERC/NYMEX(34,183)2022(40,533)2022
Fixed Swaps/FuturesFixed Swaps/Futures(21,255)2021(30,113)2021Fixed Swaps/Futures(34,183)2022(40,533)2022
Hedged Item – InventoryHedged Item – Inventory21,255 202130,113 2021Hedged Item – Inventory34,183 202240,533 2022
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
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The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
TermTerm
Type(1)
Notional Amount OutstandingTerm
Type(1)
Notional Amount Outstanding
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
July 2021(2)(3)
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate$— $400 
July 2022(2)
July 2022(2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate400 400 
July 2022(2)
Forward-starting to pay an average fixed rate of 3.80% and receive a floating rate$— $400 
July 2023(2)
July 2023(2)
Forward-starting to pay a fixed rate of 3.78% and receive a floating rate200 — 
July 2023(2)
Forward-starting to pay an average fixed rate of 3.845% and receive a floating rate400 200 
July 2024(2)
July 2024(2)
Forward-starting to pay a fixed rate of 3.88% and receive a floating rate200 — 
July 2024(2)
Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate400 200 
(1)Floating rates are based on either SOFR or 3-month LIBOR.
(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
(3)The July 2021 interest rate swaps were amended in June 2021.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in our statement of operations or statement of comprehensive income (loss).income.
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Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
Fair Value of Derivative InstrumentsFair Value of Derivative Instruments
Asset DerivativesLiability DerivativesAsset DerivativesLiability Derivatives
September 30,
2021
December 31,
2020
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
September 30,
2022
December 31,
2021
Derivatives designated as hedging instruments:Derivatives designated as hedging instruments:Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)Commodity derivatives (margin deposits)$$25 $(20)$(32)Commodity derivatives (margin deposits)$113 $46 $(77)$(3)
25 (20)(32)113 46 (77)(3)
Derivatives not designated as hedging instruments:Derivatives not designated as hedging instruments:Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)Commodity derivatives (margin deposits)330 90 (400)(166)Commodity derivatives (margin deposits)666 173 (489)(156)
Commodity derivativesCommodity derivatives702 53 (661)(71)Commodity derivatives104 53 (94)(52)
Interest rate derivativesInterest rate derivatives— — (376)(448)Interest rate derivatives— — (84)(387)
1,032 143 (1,437)(685)770 226 (667)(595)
Total derivativesTotal derivatives$1,034 $168 $(1,457)$(717)Total derivatives$883 $272 $(744)$(598)
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
Asset DerivativesLiability DerivativesAsset DerivativesLiability Derivatives
Balance Sheet LocationSeptember 30,
2021
December 31,
2020
September 30,
2021
December 31,
2020
Balance Sheet LocationSeptember 30,
2022
December 31,
2021
September 30,
2022
December 31,
2021
Derivatives without offsetting agreementsDerivatives without offsetting agreementsDerivative liabilities$— $— $(376)$(448)Derivatives without offsetting agreementsDerivative liabilities$— $— $(84)$(387)
Derivatives in offsetting agreements:Derivatives in offsetting agreements:Derivatives in offsetting agreements:
OTC contractsOTC contractsDerivative assets (liabilities)702 53 (661)(71)OTC contractsDerivative assets (liabilities)104 53 (94)(52)
Broker cleared derivative contractsBroker cleared derivative contractsOther current assets (liabilities)332 115 (420)(198)Broker cleared derivative contractsOther current assets (liabilities)779 219 (566)(159)
Total gross derivativesTotal gross derivatives1,034 168 (1,457)(717)Total gross derivatives883 272 (744)(598)
Offsetting agreements:Offsetting agreements:Offsetting agreements:
Counterparty nettingCounterparty nettingDerivative assets (liabilities)(645)(44)645 44 Counterparty nettingDerivative assets (liabilities)(85)(43)85 43 
Counterparty nettingCounterparty nettingOther current assets (liabilities)(327)(64)327 64 Counterparty nettingOther current assets (liabilities)(410)(150)410 150 
Total net derivativesTotal net derivatives$62 $60 $(485)$(609)Total net derivatives$388 $79 $(249)$(405)
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
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The following table 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 DerivativesLocationAmount of Gain (Loss) Recognized in Income on Derivatives
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020202120202022202120222021
Derivatives not designated as hedging instruments:Derivatives not designated as hedging instruments:Derivatives not designated as hedging instruments:
Commodity derivatives – TradingCommodity derivatives – TradingCost of products sold$14 $$12 $15 Commodity derivatives – TradingCost of products sold$22 $14 $50 $12 
Commodity derivatives – Non-tradingCommodity derivatives – Non-tradingCost of products sold(71)(44)(206)53 Commodity derivatives – Non-tradingCost of products sold186 (71)(6)(206)
Interest rate derivativesInterest rate derivativesGains (losses) on interest rate derivatives55 72 (277)Interest rate derivativesGains (losses) on interest rate derivatives60 303 72 
TotalTotal$(56)$15 $(122)$(209)Total$268 $(56)$347 $(122)
13.REPORTABLE SEGMENTS
Our reportable 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.
Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation 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 are 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 segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market 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 and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted

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EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those
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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.
The following tables present financial information by segment:
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020202120202022202120222021
Revenues:Revenues:Revenues:
Intrastate transportation and storage:Intrastate transportation and storage:Intrastate transportation and storage:
Revenues from external customersRevenues from external customers$1,112 $614 $5,940 $1,615 Revenues from external customers$2,081 $1,112 $5,550 $5,940 
Intersegment revenuesIntersegment revenues105 40 1,126 148 Intersegment revenues302 105 668 1,126 
1,217 654 7,066 1,763 2,383 1,217 6,218 7,066 
Interstate transportation and storage:Interstate transportation and storage:Interstate transportation and storage:
Revenues from external customersRevenues from external customers412 466 1,317 1,365 Revenues from external customers533 412 1,591 1,317 
Intersegment revenuesIntersegment revenues33 15 Intersegment revenues16 54 33 
418 471 1,350 1,380 549 418 1,645 1,350 
Midstream:Midstream:Midstream:
Revenues from external customersRevenues from external customers560 585 1,709 1,477 Revenues from external customers1,115 560 3,399 1,709 
Intersegment revenuesIntersegment revenues2,359 792 6,081 2,088 Intersegment revenues3,756 2,359 10,447 6,081 
2,919 1,377 7,790 3,565 4,871 2,919 13,846 7,790 
NGL and refined products transportation and services:NGL and refined products transportation and services:NGL and refined products transportation and services:
Revenues from external customersRevenues from external customers4,499 2,207 11,726 5,991 Revenues from external customers5,169 4,499 16,644 11,726 
Intersegment revenuesIntersegment revenues763 416 2,048 1,466 Intersegment revenues906 763 3,265 2,048 
5,262 2,623 13,774 7,457 6,075 5,262 19,909 13,774 
Crude oil transportation and services:Crude oil transportation and services:Crude oil transportation and services:
Revenues from external customersRevenues from external customers4,577 2,849 12,497 8,873 Revenues from external customers6,415 4,577 19,640 12,497 
Intersegment revenuesIntersegment revenuesIntersegment revenues
4,578 2,850 12,498 8,877 6,416 4,578 19,642 12,498 
Investment in Sunoco LP:Investment in Sunoco LP:Investment in Sunoco LP:
Revenues from external customersRevenues from external customers4,772 2,801 12,626 8,104 Revenues from external customers6,577 4,772 19,767 12,626 
Intersegment revenuesIntersegment revenues16 53 Intersegment revenues17 44 16 
4,779 2,805 12,642 8,157 6,594 4,779 19,811 12,642 
Investment in USAC:Investment in USAC:Investment in USAC:
Revenues from external customersRevenues from external customers156 158 464 500 Revenues from external customers176 156 503 464 
Intersegment revenuesIntersegment revenuesIntersegment revenues11 
159 161 473 509 179 159 514 473 
All other:All other:All other:
Revenues from external customersRevenues from external customers576 275 2,481 995 Revenues from external customers873 576 2,281 2,481 
Intersegment revenuesIntersegment revenues120 92 303 377 Intersegment revenues211 120 480 303 
696 367 2,784 1,372 1,084 696 2,761 2,784 
EliminationsEliminations(3,364)(1,353)(9,617)(4,160)Eliminations(5,212)(3,364)(14,971)(9,617)
Total revenuesTotal revenues$16,664 $9,955 $48,760 $28,920 Total revenues$22,939 $16,664 $69,375 $48,760 
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Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020202120202022202120222021
Segment Adjusted EBITDA:Segment Adjusted EBITDA:Segment Adjusted EBITDA:
Intrastate transportation and storageIntrastate transportation and storage$172 $203 $3,209 $630 Intrastate transportation and storage$301 $172 $963 $3,209 
Interstate transportation and storageInterstate transportation and storage334 425 1,118 1,232 Interstate transportation and storage409 334 1,259 1,118 
MidstreamMidstream556 530 1,321 1,280 Midstream868 556 2,578 1,321 
NGL and refined products transportation and servicesNGL and refined products transportation and services706 762 2,089 2,099 NGL and refined products transportation and services634 706 2,097 2,089 
Crude oil transportation and servicesCrude oil transportation and services496 631 1,490 1,741 Crude oil transportation and services461 496 1,616 1,490 
Investment in Sunoco LPInvestment in Sunoco LP198 189 556 580 Investment in Sunoco LP276 198 681 556 
Investment in USACInvestment in USAC99 104 299 315 Investment in USAC109 99 313 299 
All otherAll other18 22 153 62 All other30 18 149 153 
Adjusted EBITDA (consolidated)Adjusted EBITDA (consolidated)2,579 2,866 10,235 7,939 Adjusted EBITDA (consolidated)3,088 2,579 9,656 10,235 
Depreciation, depletion and amortizationDepreciation, depletion and amortization(943)(912)(2,837)(2,715)Depreciation, depletion and amortization(1,030)(943)(3,104)(2,837)
Interest expense, net of interest capitalizedInterest expense, net of interest capitalized(558)(569)(1,713)(1,750)Interest expense, net of interest capitalized(577)(558)(1,714)(1,713)
Impairment losses— (1,474)(11)(2,803)
Gains (losses) on interest rate derivatives55 72 (277)
Impairment losses and otherImpairment losses and other(86)— (386)(11)
Gains on interest rate derivativesGains on interest rate derivatives60 303 72 
Non-cash compensation expenseNon-cash compensation expense(26)(30)(81)(93)Non-cash compensation expense(27)(26)(88)(81)
Unrealized gains (losses) on commodity risk management activitiesUnrealized gains (losses) on commodity risk management activities(19)(30)74 (27)Unrealized gains (losses) on commodity risk management activities76 (19)130 74 
Inventory valuation adjustments (Sunoco LP)Inventory valuation adjustments (Sunoco LP)11 168 (126)Inventory valuation adjustments (Sunoco LP)(40)81 168 
Losses on extinguishments of debtLosses on extinguishments of debt— — (8)(62)Losses on extinguishments of debt— — — (8)
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates(141)(169)(400)(480)Adjusted EBITDA related to unconsolidated affiliates(147)(141)(409)(400)
Equity in earnings (losses) of unconsolidated affiliates71 (32)191 46 
Impairment of investment in an unconsolidated affiliate— (129)— (129)
Equity in earnings of unconsolidated affiliatesEquity in earnings of unconsolidated affiliates68 71 186 191 
Other, netOther, net11 53 — (48)Other, net19 11 (65)— 
Income (loss) before income tax expense984 (360)5,690 (525)
Income before income tax expenseIncome before income tax expense1,404 984 4,590 5,690 
Income tax expenseIncome tax expense(77)(41)(234)(168)Income tax expense(82)(77)(159)(234)
Net income (loss)$907 $(401)$5,456 $(693)
Net incomeNet income$1,322 $907 $4,431 $5,456 
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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-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 20202021 filed with the SEC on February 19, 2021.18, 2022. 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, 20202021 filed with the SEC on February 19, 2021 and “Part II - Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 filed with the SEC on August 5, 2021.18, 2022. Additional information on forward-looking statements is discussed below in “Forward-Looking Statements.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ET”“Energy Transfer” mean Energy Transfer LP and its consolidated subsidiaries.
RECENT DEVELOPMENTS
Series H Preferred Units IssuanceWoodford Express Acquisition
On June 15, 2021,September 13, 2022, Energy Transfer completed the acquisition of 100% of the membership interests in Woodford Express, LLC, which owns a mid-continent gas gathering and processing system, for approximately $485 million in cash consideration. The system, which is located in the heart of the SCOOP play, has 450 MMcf/d of cryogenic gas processing and treating capacity and over 200 miles of gathering lines, which are connected to Energy Transfer’s pipeline network. Woodford Express, LLC repaid an aggregate principal amount of $292 million of its revolving credit facility and term loan on the closing date of the acquisition, which amount is included in the total consideration.
Energy Transfer Canada Sale
In August 2022, the Partnership issued 900,000completed the previously announced sale of its 6.500% Series H Preferred Units at a price of $1,000 per unit.51% interest in Energy Transfer Canada. The net proceeds were used to repay amounts outstanding under the Partnership’s term loan and for general partnership purposes.
Winter Storm Impacts
Winter Storm Uri, which occurred in February 2021,sale resulted in one-time impactscash proceeds to the Partnership’s consolidated net income and Adjusted EBITDA and also affected the resultsEnergy Transfer of operations in certain segments, as discussed in “Results of Operations”C$390 million (US$302 million). The recognition of the impacts of Winter Storm Uri during the nine months ended September 30, 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.
Enable AcquisitionSpindletop Assets Purchase
On February 16, 2021,In March 2022, the Partnership entered into a definitive merger agreement to acquire Enable. Underpurchased the terms of the merger agreement, Enable’s common unitholders will receive 0.8595 ofmembership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an ET common unit in exchangeunderground storage facility near Mont Belvieu, Texas, for each Enable common unit. In addition, each outstanding Enable preferred unit will be exchanged for 0.0265 of a Series G Preferred Unit, and ET will make a $10 million cash payment for Enable’s general partner. In May 2021, the Enable common unitholders voted to approve the merger. The transaction is subject to the satisfaction of customary closing conditions, including Hart-Scott-Rodino Act (“HSR”) clearance.approximately $325 million.
The Federal Trade Commission (“FTC”) has issued requests for additional information and documentary material (the “Second Request”). The effect of the Second Request is to extend the waiting period imposed by the HSR Act until 30 days after the Partnership and Enable have certified substantial compliance with the Second Request, unless that period is extended voluntarily or terminated sooner by the FTC. We continue to believe that the FTC will grant clearance of the transaction, and we remain fully committed to closing the Enable merger under the terms of the merger agreement. We expect to close the transaction in the fourth quarter of 2021.Sunoco LP Acquisition
Rollup Mergers
On April 1, 2021, ET, ETO and certain of ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). In connection with the Rollup Mergers, Sunoco Logistics Operations merged with and into ETO, with ETO surviving, and immediately thereafter, ETO merged with and into ET, with ET surviving. The impacts of the Rollup Mergers also included the following:
All of ETO’s long-term debt was assumed by ET, as more fully described in Note 7 to the consolidated financial statements in “Item 1. Financial Statements.”
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Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created ET preferred unit. A description of the ET Preferred Units is included in Note 9 to the consolidated financial statements in “Item 1. Financial Statements.”
Each of ETO’s issued and outstanding Class K, Class L, Class M and Class N units, all of which were held by ETP Holdco Corporation, a wholly-owned subsidiary of ETO, were converted into an aggregate 675,625,000 newly created Class B Units representing limited partner interests in ET.
Sunoco LP’s Acquisitions
In September and October 2021,2022, Sunoco LP acquiredcompleted the acquisition of a total of nine refined product terminalstransmix processing and terminal facility in two separate transactionsHuntington, Indiana for approximately $256 $252 million.
Quarterly Cash Distribution
In October 2021, ET2022, Energy Transfer announced its quarterly distribution of $0.1525$0.265 per unit ($0.611.06 annualized) on ETEnergy Transfer common units for the quarter ended September 30, 2021.2022.
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

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a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be 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'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'sFERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.
Even without application of the FERC’s recent rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, although changes in these components may tendbut also other pipeline costs that will continue to decrease our cost-of-service rate, other components in the cost-of-service rate calculation may increaseaffect FERC’s determination of just and result in a newly calculated cost-of-service rate that is less than, the same as, or greater than the prior cost-of-service rate.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 ETC Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of the Revised Policy Statement, changes to ROE methodology, or other FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently
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charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a cost and revenue study on April 1, 2019 and an NGAgeneral rate proceeding under Section 4 rate case on August 30, 2019.of the NGA. The Natural Gas Act Section 45 and Section 54 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. 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 reply brief on exception toopposing exceptions in this proceeding. This matter remains pending before the initial decision.FERC.
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 Pipeline Certification NOI2022 Policy Statements that willmight affect our natural gas pipeline businessor LNG facility projects, or when such proposals,new policies, if any, might become effective. Comments in response to the Pipeline Certification NOI were filed by us on May 26, 2021. We do not expect that any change in thisthese 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

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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. In a December 2020 order, FERC determined that during the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates will be permitted to adjust their indexed ceilings annually by PPI-FG plus 0.78 percent. RequestsThe FERC received requests for rehearing of theits December 17, 2020 order were filedand on January 19,20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and remain pending before FERC. Accordingly,ending June 30, 2026, liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 based on the FERC’s final determinationnew 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 have sought rehearing of the index rate coupledJanuary 20, 2022 order with FERC while others have appealed to the Fifth Circuit and DC Circuit. On May 6, 2022, FERC issued its order denying the rehearing requests. Certain shippers have now filed an appeal with the anticipated and subsequent appeals ofDC Circuit challenging the December 2020 order could adversely impact the final determination of the FERC approved index.
FERC has also implemented changes related to its treatment of federal income taxes. The change in treatment impacts two rate components. Those components are the allowance for income taxes and the amount for accumulated deferred income taxes. These changes will primarily impact any cost-of-service related filing and our revenues associated with any cost-based service could be adversely affected by future FERC or judicial rulings. However, we believe that these impacts, if any, will be minimal.May 6th rehearing order.
Results of Operations
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market 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 and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and 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.
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Consolidated Results
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
Segment Adjusted EBITDA:Segment Adjusted EBITDA:Segment Adjusted EBITDA:
Intrastate transportation and storageIntrastate transportation and storage$172 $203 $(31)$3,209 $630 $2,579 Intrastate transportation and storage$301 $172 $129 $963 $3,209 $(2,246)
Interstate transportation and storageInterstate transportation and storage334 425 (91)1,118 1,232 (114)Interstate transportation and storage409 334 75 1,259 1,118 141 
MidstreamMidstream556 530 26 1,321 1,280 41 Midstream868 556 312 2,578 1,321 1,257 
NGL and refined products transportation and servicesNGL and refined products transportation and services706 762 (56)2,089 2,099 (10)NGL and refined products transportation and services634 706 (72)2,097 2,089 
Crude oil transportation and servicesCrude oil transportation and services496 631 (135)1,490 1,741 (251)Crude oil transportation and services461 496 (35)1,616 1,490 126 
Investment in Sunoco LPInvestment in Sunoco LP198 189 556 580 (24)Investment in Sunoco LP276 198 78 681 556 125 
Investment in USACInvestment in USAC99 104 (5)299 315 (16)Investment in USAC109 99 10 313 299 14 
All otherAll other18 22 (4)153 62 91 All other30 18 12 149 153 (4)
Adjusted EBITDA (consolidated)Adjusted EBITDA (consolidated)2,579 2,866 (287)10,235 7,939 2,296 Adjusted EBITDA (consolidated)3,088 2,579 509 9,656 10,235 (579)
Depreciation, depletion and amortizationDepreciation, depletion and amortization(943)(912)(31)(2,837)(2,715)(122)Depreciation, depletion and amortization(1,030)(943)(87)(3,104)(2,837)(267)
Interest expense, net of interest capitalizedInterest expense, net of interest capitalized(558)(569)11 (1,713)(1,750)37 Interest expense, net of interest capitalized(577)(558)(19)(1,714)(1,713)(1)
Impairment losses— (1,474)1,474 (11)(2,803)2,792 
Gains (losses) on interest rate derivatives55 (54)72 (277)349 
Impairment losses and otherImpairment losses and other(86)— (86)(386)(11)(375)
Gains on interest rate derivativesGains on interest rate derivatives60 59 303 72 231 
Non-cash compensation expenseNon-cash compensation expense(26)(30)(81)(93)12 Non-cash compensation expense(27)(26)(1)(88)(81)(7)
Unrealized gains (losses) on commodity risk management activitiesUnrealized gains (losses) on commodity risk management activities(19)(30)11 74 (27)101 Unrealized gains (losses) on commodity risk management activities76 (19)95 130 74 56 
Inventory valuation adjustments (Sunoco LP)Inventory valuation adjustments (Sunoco LP)11 (2)168 (126)294 Inventory valuation adjustments (Sunoco LP)(40)(49)81 168 (87)
Losses on extinguishments of debtLosses on extinguishments of debt— — — (8)(62)54 Losses on extinguishments of debt— — — — (8)
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates(141)(169)28 (400)(480)80 Adjusted EBITDA related to unconsolidated affiliates(147)(141)(6)(409)(400)(9)
Equity in earnings (losses) of unconsolidated affiliates71 (32)103 191 46 145 
Impairment of investment in an unconsolidated affiliate— (129)129 — (129)129 
Equity in earnings of unconsolidated affiliatesEquity in earnings of unconsolidated affiliates68 71 (3)186 191 (5)
Other, netOther, net11 53 (42)— (48)48 Other, net19 11 (65)— (65)
Income (loss) before income tax expense984 (360)1,344 5,690 (525)6,215 
Income before income tax expenseIncome before income tax expense1,404 984 420 4,590 5,690 (1,100)
Income tax expenseIncome tax expense(77)(41)(36)(234)(168)(66)Income tax expense(82)(77)(5)(159)(234)75 
Net income (loss)$907 $(401)$1,308 $5,456 $(693)$6,149 
Net incomeNet income$1,322 $907 $415 $4,431 $5,456 $(1,025)
Adjusted EBITDA (consolidated). For the three months ended September 30, 20212022 compared to the same period last year, Adjusted EBITDA increased 20% primarily due to the impacts of the recent Enable Acquisition, which contributed $395 million of margin in our midstream segment and $137 million of margin in our interstate transportation and storage segment. In addition, the increase in Adjusted EBITDA also reflected a favorable impact of $33 million from natural gas and NGL prices in our midstream segment.
For the nine months ended September 30, 2022 compared to the same period last year, Adjusted EBITDA decreased 10% due to the net impacts of multiple factors across each of our reportable segments. The primary drivers of the Adjusted EBITDA decrease were in our interstate transportation and storage, NGL and refined products transportation and services, and crude oil transportation and services segments. In our interstate transportation and storage segment, the decrease in Adjusted EBITDA was primarily driven by shipper contract expirations and a shipper bankruptcy. In our NGL and refined products transportation and services segment, the decrease in Adjusted EBITDA was primarily driven by increased utilities and employee related costs, while several variances within our segment margin were largely offsetting. In our crude oil transportation and services segment, the decrease in Adjusted EBITDA reflected a decrease in margin from our crude oil acquisition and marketing business, as well as increases in operating expense and selling, general and administrative expenses.
For the nine months ended September 30, 2021 compared to the same period last year, Adjusted EBITDA increased 29%,6% primarily due to the impacts of Winter Storm Uri in February 2021. The most significant impacts from the storm were recognized in our intrastate transportation and storage segment, where Segment Adjusted EBITDA decreased by $2.25 billion primarily due to a $1.52 billion decrease in realized storage margin increased by $1.52 billion compared to the prior period as a result of withdrawals during the storm. In addition,and an $744 million decrease in realized natural gas sales, increased $936 million and retained fuel revenues increased $114 million in our intrastate transportation and storage segment, and these increasesboth of which were also primarily due to the impactsimpact of Winter Storm Uri in the prior period. These decreases were partially offset by favorable results in multiple segments, the most significant of which were in our midstream segment, where Segment Adjusted EBITDA increased by $1.26 billion primarily due to favorable natural gas and NGL prices and the impact of the storm.
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recent Enable Acquisition.
Additional information on changes impacting Adjusted EBITDA for the three and nine months ended September 30, 20212022 compared to the same periods last year, including other impacts from Winter Storm Uri and other non-storm-related factors, is available below in “Segment Operating Results.”
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and nine months ended September 30, 20212022 compared to the same period last year primarily due to incremental depreciation and amortization related to the Enable assets acquired in December 2021 and assets recently placed in service.

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Interest Expense, net. Interest expense, net of interest capitalized, decreasedincreased for the three and nine months ended September 30, 20212022 compared to the same periodsperiod last year, primarily due to the following:
the Partnership’s interest expense increased by $7 million due to an increase in average long-term debt resulting from the Enable Acquisition as well as higher interest rates on floating rate debt.
Sunoco LP’s interest expense increased by $9 million due to an increase in average total long-term debt and an increase in the weighted average interest rate on long-term debt.
USAC’s interest expense increased by $3 million due to higher weighted-average interest rates and increased borrowings under its credit agreement, partially offset by a decrease in amortization of debt issuance costs related to the amendment and restatement of its credit agreement since the prior period.
Interest expense, net of interest capitalized, increased for the nine months ended September 30, 2022 compared to the same period last year, primarily due to the following:
the Partnership’s interest expense decreased $8by $13 million due to lower non-cash interest expense in the current period, partially offset by an increase in average long-term debt resulting from the Enable Acquisition as well as higher interest rates on floating rate debt.
Sunoco LP’s interest expense increased by $11 million due to an increase in average total long-term debt and $30an increase in the weighted average interest rate on long-term debt.
USAC’s interest expense increased by $3 million due to higher weighted-average interest rates and increased borrowings under its credit agreement, partially offset by a decrease in amortization of debt issuance costs related to the amendment and restatement of its credit agreement since the prior period.
Impairment Losses and Other. For the three months ended September 30, 2022, impairment losses and other included an $85 million loss on the deconsolidation of Energy Transfer Canada, which was recorded upon the completion of the sale in August 2022. The nine months ended September 30, 2022 amount also included a $300 million impairment related to Energy Transfer Canada’s assets recorded in March 2022 based on the anticipated proceeds from the expected sale of those assets. The remainder of the impairment losses for the three and nine months ended September 30, 2021, respectively, primarily due2022 were from USAC’s recognition of impairment losses related to lower total debt outstanding and lower borrowing costs on recently refinanced and floating rate debt, partially offset by lower interest capitalized; andits compression equipment.
Sunoco LP’s interest expense decreased $3 million and $7 million for the three and nine months ended September 30, 2021, respectively, primarily attributable to a slight decrease in average total long-term debt and decrease in the weighted average interest rate on long-term debt for the respective periods.
Impairment Losses. For the nine months ended September 30, 2021 impairment losses included a total of $5 million recognized by USAC related to its compression equipment, as well as a $6 million impairment of intangible assets related to customer contracts within the Partnership’s crude operations.
For the three months ended September 30, 2020, the Partnership recognized goodwill impairments totaling $1.46 billion and fixed asset impairments totaling $19 million primarily due to decreases in projected future cash flow as a result of the overall market demand decline. In addition, USAC recognized an equipment impairment of $2 million based on changes in market conditions. For the nine months ended September 30, 2020, impairment losses also included goodwill impairments recognized by the Partnership during the first quarter of 2020 totaling $706 million due to decreases in projected future cash flows as a result of overall market demand decline and a goodwill impairment recognized by USAC of $619 million, as well as an equipment impairment of $4 million based on changes in market conditions during the second quarter of 2020.
Gains (Losses) on Interest Rate Derivatives. Gains and losses on interest rate derivatives during the three and nine months ended September 30, 20212022 resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and in Note 12 to our consolidated financial statements included in “Item 1. Financial Statements.”
Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the three months ended September 30, 2021 and September 30, 2020, increases2022 a decrease in fuel prices reducedincreased lower of cost or market reserve requirements by $9$40 million, and $11 million, respectively.resulting in an adverse impact to net income. For the ninethree months ended September 30, 2021, an increase in fuel prices reduced lower of cost or market reserve requirements for the period by $168 million.$9 million, resulting in a favorable impact to net income. For the nine months ended September 30, 2020, a decline2022 and September 30, 2021, an increase in fuel prices increasedreduced lower of cost or market reserve requirements for the period by $126$81 million and $168 million, respectively, resulting in an adverse impactfavorable impacts to net income.
Losses on Extinguishments of Debt. DuringFor the nine months ended September 30, 2021, the lossesloss on extinguishmentsextinguishment of debt also includedwas related to the Partnership’s partial repayment of its Term Loan in April 2021 as well as Sunoco LP’s January 2021 repurchase of the remainder of its 2023 senior notes as well as the Partnership’s partial repayment of its Term Loan in April 2021. During the nine months ended September 30, 2020, amounts were related to ETO’s senior notes redemption in January 2020.notes.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operating Results” below.
Impairment of Investment in an Unconsolidated Affiliate. During the three and nine months ended September 30, 2020, the Partnership recorded an impairment to its investment in White Cliffs of $129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to the SemGroup, LLC acquisition and related purchase price allocation in December 2019.
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Other, net. Other, net primarily includes the amortization of regulatory assets and other income and expense amounts.
Income Tax Expense. For the three and nine months ended September 30, 20212022 compared to the same periodsperiod last year, income tax expense increased due to higher earnings from the Partnership’s consolidated subsidiaries, partially offset by a favorable state tax rate change in the current period. For the nine months ended September 30, 2022 compared to the same period last year, income tax expense decreased due to lower earnings from the Partnership’s consolidated corporate subsidiaries.subsidiaries and a favorable state tax rate change in the current period.
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
Equity in earnings (losses) of unconsolidated affiliates:Equity in earnings (losses) of unconsolidated affiliates:Equity in earnings (losses) of unconsolidated affiliates:
CitrusCitrus$44 $50 $(6)$123 $127 $(4)Citrus$36 $44 $(8)$109 $123 $(14)
FEP (1)
— (106)106 — (158)158 
MEPMEP(5)(1)(4)(12)(3)(9)MEP(1)(5)(7)(12)
White CliffsWhite Cliffs(1)(3)— 19 (19)White Cliffs— (1)— 
ExplorerExplorer(1)17 20 (3)
OtherOther33 23 10 80 61 19 Other25 24 66 60 
Total equity in earnings (losses) of unconsolidated affiliates$71 $(32)$103 $191 $46 $145 
Total equity in earnings of unconsolidated affiliatesTotal equity in earnings of unconsolidated affiliates$68 $71 $(3)$186 $191 $(5)
Adjusted EBITDA related to unconsolidated affiliates(2):
Adjusted EBITDA related to unconsolidated affiliates(1):
Adjusted EBITDA related to unconsolidated affiliates(1):
CitrusCitrus$87 $96 $(9)$251 $264 $(13)Citrus$86 $87 $(1)$245 $251 $(6)
FEP— 19 (19)— 57 (57)
MEPMEP(4)14 23 (9)MEP19 14 
White CliffsWhite Cliffs11 (7)14 38 (24)White Cliffs15 14 
ExplorerExplorer12 12 — 28 31 (3)
OtherOther46 35 11 121 98 23 Other36 34 102 90 12 
Total Adjusted EBITDA related to unconsolidated affiliatesTotal Adjusted EBITDA related to unconsolidated affiliates$141 $169 $(28)$400 $480 $(80)Total Adjusted EBITDA related to unconsolidated affiliates$147 $141 $$409 $400 $
Distributions received from unconsolidated affiliates:Distributions received from unconsolidated affiliates:Distributions received from unconsolidated affiliates:
CitrusCitrus$106 $48 $58 $191 $155 $36 Citrus$52 $106 $(54)$133 $191 $(58)
FEP— 20 (20)55 (51)
MEPMEP(3)22 (13)MEP14 
White CliffsWhite Cliffs25 25 — White Cliffs— 15 25 (10)
ExplorerExplorer— 20 20 — 
OtherOther26 24 73 63 10 Other27 20 66 57 
Total distributions received from unconsolidated affiliatesTotal distributions received from unconsolidated affiliates$138 $98 $40 $302 $320 $(18)Total distributions received from unconsolidated affiliates$94 $138 $(44)$248 $302 $(54)
(1)For the three and nine months ended September 30, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $123 million and $208 million, respectively.
(2)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
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The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:
Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. 
In theThe following analysis of segment operating results includes a measure of segment margin is reported for segments with sales revenues.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 sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s Adjusted EBITDA and also affected the results of operations in certain segments, as discussed in segment analysis. The recognition of the impacts of Winter Storm Uri during the ninethree months ended September 30,March 31, 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.
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Intrastate Transportation and Storage
Three Months Ended
September 30,
Nine Months Ended
September 30,
 Three Months Ended
September 30,
Nine Months Ended
September 30,
 
20212020Change20212020Change20222021Change20222021Change
Natural gas transported (BBtu/d)Natural gas transported (BBtu/d)12,335 12,185 150 12,465 12,745 (280)Natural gas transported (BBtu/d)14,878 11,601 3,277 14,565 11,674 2,891 
Withdrawals from storage natural gas inventory (BBtu)Withdrawals from storage natural gas inventory (BBtu)2,350 10,315 (7,965)32,038 15,380 16,658 Withdrawals from storage natural gas inventory (BBtu)— 2,350 (2,350)21,858 32,038 (10,180)
RevenuesRevenues$1,217 $654 $563 $7,066 $1,763 $5,303 Revenues$2,383 $1,217 $1,166 $6,218 $7,066 $(848)
Cost of products soldCost of products sold978 434 544 3,636 985 2,651 Cost of products sold1,994 978 1,016 5,008 3,636 1,372 
Segment marginSegment margin239 220 19 3,430 778 2,652 Segment margin389 239 150 1,210 3,430 (2,220)
Unrealized (gains) losses on commodity risk management activitiesUnrealized (gains) losses on commodity risk management activities(1)23 (24)(18)(16)(2)Unrealized (gains) losses on commodity risk management activities12 (1)13 17 (18)35 
Operating expenses, excluding non-cash compensation expenseOperating expenses, excluding non-cash compensation expense(64)(42)(22)(199)(131)(68)Operating expenses, excluding non-cash compensation expense(93)(64)(29)(251)(199)(52)
Selling, general and administrative expenses, excluding non-cash compensation expenseSelling, general and administrative expenses, excluding non-cash compensation expense(8)(7)(1)(25)(22)(3)Selling, general and administrative expenses, excluding non-cash compensation expense(12)(8)(4)(37)(25)(12)
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates(1)19 19 — Adjusted EBITDA related to unconsolidated affiliates(1)18 19 (1)
OtherOther— (2)— Other— — — 
Segment Adjusted EBITDASegment Adjusted EBITDA$172 $203 $(31)$3,209 $630 $2,579 Segment Adjusted EBITDA$301 $172 $129 $963 $3,209 $(2,246)
Volumes. For the three months ended September 30, 20212022 compared to the same period last year, transported volumes increased primarily due to the acquisition of the Enable Oklahoma Intrastate Transmission system, as well as increased production increases in the Permian.Haynesville.
For the nine months ended September 30, 20212022 compared to the same period last year, transported volumes decreasedincreased primarily due to the bankruptcy filingacquisition of a transportation customer, a contract step-down,the Enable Oklahoma Intrastate Transmission system, as well as increased production in the Permian and impacts of Winter Storm Uri.Haynesville.
Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
Three Months Ended
September 30,
Nine Months Ended
September 30,
 Three Months Ended
September 30,
Nine Months Ended
September 30,
 
20212020Change20212020Change20222021Change20222021Change
Transportation feesTransportation fees$162 $151 $11 $542 $460 $82 Transportation fees$202 $162 $40 $613 $542 $71 
Natural gas sales and other (excluding unrealized gains and losses)Natural gas sales and other (excluding unrealized gains and losses)39 75 (36)1,167 231 936 Natural gas sales and other (excluding unrealized gains and losses)139 39 100 423 1,167 (744)
Retained fuel revenues (excluding unrealized gains and losses)Retained fuel revenues (excluding unrealized gains and losses)29 12 17 145 31 114 Retained fuel revenues (excluding unrealized gains and losses)59 29 30 150 145 
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)1,558 40 1,518 Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)— (8)40 1,558 (1,518)
Unrealized gains on commodity risk management activities and fair value inventory adjustments(23)24 18 16 
Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustmentsUnrealized gains (losses) on commodity risk management activities and fair value inventory adjustments(11)(12)(16)18 (34)
Total segment marginTotal segment margin$239 $220 $19 $3,430 $778 $2,652 Total segment margin$389 $239 $150 $1,210 $3,430 $(2,220)
Segment Adjusted EBITDA. For the three months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreasedincreased due to the net effectsimpacts of the following:
a decreasean increase of $36$100 million in realized natural gas sales and other primarily due to lower optimization volumes with shiftshigher optimization;
an increase of $40 million in transportation fees primarily due to long-term third-party contractsfees from the Permian to the Gulf Coast and lower spreads;Enable Oklahoma Intrastate Transmission System; and
an increase of $22$29 million in operating expenses primarily due to increases of $9 million in cost ofretained fuel consumption duerevenues related to higher natural gas prices, $6 million in maintenance project costs, $3 million in employee related expenses, and $3 million in ad valorem taxes;prices; partially offset by
an increase of $11$29 million in transportation feesoperating expenses primarily due to increased firm transportation volumesa $17 million increase in cost of fuel consumption, a $7 million increase from additional expenses from the Permian;Enable assets and a $4 million increase in utilities expenses;

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a decrease of $8 million in storage margin primarily due to lower storage optimization; and
an increase of $17$4 million in retained fuel revenuesselling, general and administrative expenses primarily due to higher natural gas prices; and
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Enablean increase of $3 million in realized storage margin due to higher storage optimization..
Segment Adjusted EBITDA. For the nine months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment increased due to the net effects of the following:
an increase of $1.52 billion in realized storage margin due to higher physical storage margin from withdrawals during Winter Storm Uri;
an increase of $936 million in realized natural gas sales and other primarily due to natural gas sales during Winter Storm Uri;
an increase of $114 million in retained fuel revenues primarily due to higher natural gas prices during Winter Storm Uri; and
an increase of $82 million in transportation fees due to revenues from Winter Storm Uri and demand volume ramp-ups from the Permian, partially offset by the expiration of certain contracts on our Regency Intrastate Gas System; partially offset by
an increase of $68 million in operating expenses primarily due to increases of $45 million in cost of fuel consumption and $4 million in electricity costs, both of which were primarily due to higher gas prices related to Winter Storm Uri, as well as increases of $9 million in maintenance project costs, $7 million in employee related costs, and $3 million in outside services and material costs.
Interstate Transportation and Storage
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change
Natural gas transported (BBtu/d)9,917 10,387 (470)9,769 10,422 (653)
Natural gas sold (BBtu/d)16 15 18 16 
Revenues$418 $471 $(53)$1,350 $1,380 $(30)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(152)(147)(5)(429)(429)— 
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(21)(20)(1)(63)(57)(6)
Adjusted EBITDA related to unconsolidated affiliates91 122 (31)265 343 (78)
Other(2)(1)(1)(5)(5)— 
Segment Adjusted EBITDA$334 $425 $(91)$1,118 $1,232 $(114)
Volumes. For the three and nine months ended September 30, 2021 compared to the same periods last year, transported volumes decreased primarily due to foundation shipper contract expirations and a shipper bankruptcy on our Tiger system, as well as lower utilization resulting from unfavorable market conditions on our Trunkline system.
Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
a decrease of $53 million$1.52 billion in revenuesrealized storage margin primarily due to a $37 million decline resultinghigher physical storage margin from shipper contract expirations on our Tiger system and an $18 million decline due to a shipper bankruptcywithdrawals during 2020 also on our Tiger system. In addition, transportation revenues decreased by $16 million on our Panhandle and Trunkline systems due to lower demand. These decreases were partially offset by an increase of $13 millionWinter Storm Uri in transportation revenue from our Rover system as a result of more favorable market conditions;the prior period;
an increasea decrease of $5$744 million in operating expensesrealized natural gas sales and other primarily due to a $7 million increase from the revaluation of systemnatural gas a $5 million increase in maintenance project costs, a $3 million increase in employee costs, and $2 million increase in ad valorem taxes; partially offset by a decrease in credit lossessales at prevailing market prices during Winter Storm Uri in the prior period;
an increase of $1$52 million in operating expenses primarily due to a $23 million increase from additional expenses from the Enable assets, a $20 million increase in cost of fuel consumption from higher gas prices, a $4 million increase in ad valorem taxes and a $4 million increase in utilities expense; and
an increase of $12 million in selling, general and administrative expenses primarily due to the addition of Enable and higher allocated overhead costs and employee costs; andlegal expenses; partially offset by
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a decreasean increase of $31$71 million in Adjusted EBITDA related to unconsolidated affiliatestransportation fees primarily due to a $19fees on the recently acquired Enable Oklahoma Intrastate Transmission system, partially offset by fees related to Winter Storm Uri in the prior period; and
an increase of $5 million decrease from our Fayetteville Express Pipeline joint venture as a resultin retained fuel revenues related to natural gas prices.
Interstate Transportation and Storage
Three Months Ended
September 30,
Nine Months Ended
September 30,
20222021Change20222021Change
Natural gas transported (BBtu/d)14,157 9,917 4,240 14,359 9,769 4,590 
Natural gas sold (BBtu/d)28 16 12 30 18 12 
Revenues$549 $418 $131 $1,645 $1,350 $295 
Cost of products sold— 24 — 24 
Segment margin546 418 128 1,621 1,350 271 
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(219)(152)(67)(590)(429)(161)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(37)(21)(16)(100)(63)(37)
Adjusted EBITDA related to unconsolidated affiliates106 91 15 293 265 28 
Other13 (2)15 35 (5)40 
Segment Adjusted EBITDA$409 $334 $75 $1,259 $1,118 $141 
Volumes. For the three and nine months ended September 30, 2022 compared to the same periods last year, transported volumes increased primarily due to the impact of the expiration of foundation shipper contracts, a $9 million decrease fromEnable Acquisition, higher utilization on our Citrus joint ventureTiger system due to a contractual rate adjustmentincreased production in the Haynesville Shale and a $3 million decrease fromhigher volumes on our Midcontinent Express Pipeline joint ventureTrunkline system due to lower rates on short-term capacity.increased demand.
Segment Adjusted EBITDA. For the ninethree months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreasedincreased due to the net impacts of the following:
a decreasean increase of $30$128 million in revenuessegment margin primarily due to a $97$137 million decline resultingincrease as a result of higher volumes from shipper contract expirations on our Tiger systemthe Enable Acquisition and increased production in the Haynesville Shale and Permian Basin and a $37$2 million declineincrease due to higher volumes and higher rates from operational gas sales. These increases were partially offset by a $5 million decrease due to a shipper bankruptcy during 2020 also on our Tiger system. In addition, revenues decreased by $25 million on our Panhandle and Trunkline systems due to lower demand. These decreases were partially offset by increased transportation revenues of $30 million from our Rover system and a $96$6 million increasedecrease on our Panhandle system resulting from developments in operational gas sales;an ongoing rate case;

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an increase of $6 million in selling, general and administrative expenses primarily resulting from higher allocated overhead and employee costs; and
a decrease of $78$15 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an increase of $12 million resulting from the Enable Acquisition and a $57$3 million decreaseincrease from our FayettevilleMidcontinent Express Pipeline joint venture as a result of higher revenue due to capacity sold at higher rates; and
an increase of $15 million in other primarily due to the expirationrealization in the current period of foundationcertain amounts related to a shipper contracts,bankruptcy that occurred in a $13prior period; partially offset by
an increase of $67 million in operating expenses primarily due to a $71 million increase from the impact of the Enable Acquisition and a $3 million increase in maintenance related expenses, partially offset by a $7 million decrease from shipper imbalances; and
an increase of $16 million in selling, general and administrative expenses primarily due to the impact of the Enable Acquisition.
Segment Adjusted EBITDA. For the nine months ended September 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
an increase of $271 million in segment margin primarily due to a $402 million increase as a result of higher volumes from the Enable Acquisition and increased production from the Haynesville Shale and Permian Basin, a $10 million increase due to higher volumes and higher rates from operational gas sales. These increases were partially offset by an $86 million decrease due to Winter Storm Uri related gains recorded in the prior period, $34 million in lower reservation fees resulting from shipper contract expirations and a shipper bankruptcy and a $23 million decrease due to lower rates on our Panhandle system resulting from developments in an ongoing rate case;
an increase of $28 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an increase of $27 million from the Enable Acquisition and a $5 million increase from our Midcontinent Express Pipeline joint venture as a result of higher revenue due to capacity sold at higher rates. These increases were partially offset by a $5 million decrease from our Citrus joint venture due to higher project expenses and allocated costs as well as lower revenue resulting from a contractual rate adjustment,case settlement; and
an $8increase of $40 million decrease from our Midcontinent Express Pipeline joint venturein other primarily due to capacity sold at lower rates.the realization in the current period of certain amounts related to a shipper bankruptcy that occurred in a prior period; partially offset by
an increase of $161 million in operating expenses primarily due to a $144 million increase from the impact of the Enable Acquisition and a $16 million increase in maintenance project costs and materials; and
an increase of $37 million in selling, general and administrative expenses primarily due to the impact of the Enable Acquisition.
Midstream
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
Gathered volumes (BBtu/d)Gathered volumes (BBtu/d)12,991 12,904 87 12,712 13,071 (359)Gathered volumes (BBtu/d)19,107 12,991 6,116 18,264 12,712 5,552 
NGLs produced (MBbls/d)NGLs produced (MBbls/d)667 635 32 624 616 NGLs produced (MBbls/d)814 667 147 795 624 171 
Equity NGLs (MBbls/d)Equity NGLs (MBbls/d)37 32 35 35 — Equity NGLs (MBbls/d)43 37 44 35 
RevenuesRevenues$2,919 $1,377 $1,542 $7,790 $3,565 $4,225 Revenues$4,871 $2,919 $1,952 $13,846 $7,790 $6,056 
Cost of products soldCost of products sold2,153 668 1,485 5,864 1,716 4,148 Cost of products sold3,678 2,153 1,525 10,418 5,864 4,554 
Segment marginSegment margin766 709 57 1,926 1,849 77 Segment margin1,193 766 427 3,428 1,926 1,502 
Operating expenses, excluding non-cash compensation expenseOperating expenses, excluding non-cash compensation expense(191)(169)(22)(551)(528)(23)Operating expenses, excluding non-cash compensation expense(275)(191)(84)(768)(551)(217)
Selling, general and administrative expenses, excluding non-cash compensation expenseSelling, general and administrative expenses, excluding non-cash compensation expense(28)(21)(7)(80)(67)(13)Selling, general and administrative expenses, excluding non-cash compensation expense(55)(28)(27)(140)(80)(60)
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates(1)23 23 — Adjusted EBITDA related to unconsolidated affiliates(3)20 23 (3)
OtherOther(1)— Other— (1)38 35 
Segment Adjusted EBITDASegment Adjusted EBITDA$556 $530 $26 $1,321 $1,280 $41 Segment Adjusted EBITDA$868 $556 $312 $2,578 $1,321 $1,257 
Volumes. Gathered volumes and NGL production increased during the three and nine months ended September 30, 20212022 compared to the same periodperiods last year primarily due to volume increases in the Permian, Ark-La-Tex, and South Texas regions, partially offset by volume declines in the Northeast and Mid-Continent/Panhandleall regions.
Gathered volumes and NGL production decreased during the nine months ended September 30, 2021 compared to the same period last year primarily due to volume decreases in the South Texas, Mid-Continent/Panhandle, Northeast and North Texas regions partially offset by volume growth in the Permian and Ark-La-Tex regions.

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Segment Margin. The components of our midstream segment gross margin were as follows:
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
Gathering and processing fee-based revenuesGathering and processing fee-based revenues$535 $642 $(107)$1,555 $1,675 $(120)Gathering and processing fee-based revenues$806 $535 $271 $2,248 $1,555 $693 
Non-fee-based contracts and processingNon-fee-based contracts and processing231 67 164 371 174 197 Non-fee-based contracts and processing387 231 156 1,180 371 809 
Total segment marginTotal segment margin$766 $709 $57 $1,926 $1,849 $77 Total segment margin$1,193 $766 $427 $3,428 $1,926 $1,502 
Segment Adjusted EBITDA. For the three months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:
an increase of $156$33 million in non-fee-based margin due to favorable NGL prices of $96 million and natural gas prices of $60$25 million and NGL prices of $8 million;
an increase of $124 million in non-fee-based margin due to the Enable Acquisition in December 2021; and
an increase of $8 million in non-fee-based margin due to increased throughput in the Permian region and the ramp-up of recently completed assets in the Northeast region; partially offset by
a decrease of $107$271 million in fee-based margin due to the recognition of $103 million related to the restructuring and assignment of certain gathering and processing contractsEnable Acquisition in December 2021, as well as increased production in the Ark-La-Tex region in the third quarter of 2020;Permian and South Texas regions; partially offset by
an increase of $22$84 million in operating expenses due to an increase of $15$64 million in employeeincremental operating expenses related to the Enable assets acquired in December 2021 and an $18 million increase in maintenance project costs and $6 millionmaterials in outside services;the South Texas and Permian regions; and
an increase of $7$27 million in selling, general and administrative expenses primarily due to higher allocated overhead costs.a $10 million increase from the impact of the Enable Acquisition and a $13 million increase in insurance and legal fees.
Segment Adjusted EBITDA. For the nine months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:
an increase of $319$276 million in non-fee-based margin due to favorable NGL prices of $197 million and natural gas prices of $122$120 million and NGL prices of $156 million; and
an increase of $21$391 million in non-fee-based margin due to the Enable Acquisition in December 2021, as well as increased throughputproduction in the Permian region and the ramp-up of recently completed assets in the Northeast region; partially offset bySouth Texas regions;
a decreasean increase of $143 million in non-fee-based margin due to the impacts of Winter Storm Uri;Uri in the prior period; and
a decreasean increase of $120$693 million in fee-based margin due to the recognition of $103 million related to the restructuring and assignment of certain gathering and processing contractsEnable Acquisition in the Ark-La-Tex region in the third quarter of 2020,December 2021, as well as volume declinesincreased production in the current period;Permian, Northeast and South Texas regions; partially offset by
an increase of $23$217 million in operating expenses due to an increase of $35$163 million in employeeincremental operating expenses related to the Enable assets acquired in December 2021, a $36 million increase in maintenance project costs offset byand materials in the South Texas and Permian regions, a decrease of $9 million increase in outside servicesfuel prices, a $3 million increase in office expenses and $2a $3 million increase in materials;right-of-way licensing fees; and
an increase of $13$60 million in selling, general and administrative expenses due to higher allocated overhead costs.a $37 million increase from the impact of the Enable Acquisition and a $20 million increase in legal fees.
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NGL and Refined Products Transportation and Services
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
NGL transportation volumes (MBbls/d)NGL transportation volumes (MBbls/d)1,803 1,493 310 1,685 1,431 254 NGL transportation volumes (MBbls/d)1,892 1,803 89 1,852 1,685 167 
Refined products transportation volumes (MBbls/d)Refined products transportation volumes (MBbls/d)526 460 66 500 460 40 Refined products transportation volumes (MBbls/d)543 526 17 522 500 22 
NGL and refined products terminal volumes (MBbls/d)NGL and refined products terminal volumes (MBbls/d)1,237 850 387 1,156 813 343 NGL and refined products terminal volumes (MBbls/d)1,287 1,237 50 1,265 1,156 109 
NGL fractionation volumes (MBbls/d)NGL fractionation volumes (MBbls/d)884 877 815 839 (24)NGL fractionation volumes (MBbls/d)940 884 56 895 815 80 
RevenuesRevenues$5,262 $2,623 $2,639 $13,774 $7,457 $6,317 Revenues$6,075 $5,262 $813 $19,909 $13,774 $6,135 
Cost of products soldCost of products sold4,347 1,712 2,635 11,035 4,916 6,119 Cost of products sold5,044 4,347 697 16,921 11,035 5,886 
Segment marginSegment margin915 911 2,739 2,541 198 Segment margin1,031 915 116 2,988 2,739 249 
Unrealized (gains) losses on commodity risk management activities(2)11 (13)(71)34 (105)
Unrealized gains on commodity risk management activitiesUnrealized gains on commodity risk management activities(126)(2)(124)(158)(71)(87)
Operating expenses, excluding non-cash compensation expenseOperating expenses, excluding non-cash compensation expense(207)(162)(45)(573)(475)(98)Operating expenses, excluding non-cash compensation expense(265)(207)(58)(708)(573)(135)
Selling, general and administrative expenses, excluding non-cash compensation expenseSelling, general and administrative expenses, excluding non-cash compensation expense(27)(20)(7)(82)(64)(18)Selling, general and administrative expenses, excluding non-cash compensation expense(33)(27)(6)(96)(82)(14)
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates26 22 75 63 12 Adjusted EBITDA related to unconsolidated affiliates27 26 71 75 (4)
OtherOther— — Other— (1)— (1)
Segment Adjusted EBITDASegment Adjusted EBITDA$706 $762 $(56)$2,089 $2,099 $(10)Segment Adjusted EBITDA$634 $706 $(72)$2,097 $2,089 $
Volumes. For the three and nine months ended September 30, 20212022 compared to the same periods last year, NGL transportation volumes increased primarily due to higher volumes from the initiation of servicePermian and Eagle Ford regions and higher volumes on our propane and ethane export pipelines into our Nederland Terminal in the fourth quarter of 2020, higher volumes from the Eagle Ford region and higher volumes on our Mariner East and West pipeline systems. For the nine months ended September 30, 2021 compared to the same period last year, the increase in NGL transportation volumes was partially offset by lower volumes caused by production interruptions, primarily in the Permian region, due to Winter Storm Uri during the first quarter of 2021.Terminal.
Refined products transportation volumes increased for the three and nine months ended September 30, 20212022 compared to the same periods last year due to recovery from COVID-19 related demand reduction in the prior period.
NGL and refined products terminal volumes increased for the three and nine months ended September 30, 20212022 compared to the same periods last year primarily due to the previously mentioned start of newhigher volumes on our export pipelines and refined product demand recovery.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility decreasedincreased for the three and nine months ended September 30, 20212022 compared to the same periodperiods last year primarily due to lower NGL volumes feedingincreased production to our Mont Belvieu fractionation facility as a result of production interruptions,system, primarily infrom the Permian region, due to Winter Storm Uri during the first quarter of 2021.
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and Eagle Ford regions.
Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
Transportation marginTransportation margin$514 $494 $20 $1,495 $1,419 $76 Transportation margin$553 $514 $39 $1,552 $1,495 $57 
Fractionators and refinery services marginFractionators and refinery services margin182 189 (7)510 541 (31)Fractionators and refinery services margin227 182 45 627 510 117 
Terminal services marginTerminal services margin166 130 36 470 410 60 Terminal services margin179 166 13 521 470 51 
Storage marginStorage margin63 63 — 200 181 19 Storage margin72 63 211 200 11 
Marketing marginMarketing margin(12)46 (58)(7)24 (31)Marketing margin(126)(12)(114)(81)(7)(74)
Unrealized gains (losses) on commodity risk management activities(11)13 71 (34)105 
Unrealized gains on commodity risk management activitiesUnrealized gains on commodity risk management activities126 124 158 71 87 
Total segment marginTotal segment margin$915 $911 $$2,739 $2,541 $198 Total segment margin$1,031 $915 $116 $2,988 $2,739 $249 

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Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impacts of the following:
a decrease of $58 million in marketing margin primarily due to a $36 million decrease in optimization gains and from the sale of NGL component products at our Mont Belvieu facility and a $19 million decrease in northeast blending and optimization primarily due to realized losses on financial instruments and increased costs related to renewable identification numbers (“RINs”), and a $6 million decrease due to optimization gains realized in 2020 as marketing prices increased.These decreases were partially offset by a $4 million increase in butane blending margin due to more favorable spreads and incremental gasoline blending in the third quarter of 2021;
an increase of $45 million in operating expenses primarily due to a $21 million increase in utilities cost, a $16 million increase in employee related costs, a $6 million increase in materials and other associated costs to run the assets and a $2 million increase in allocated corporate overhead costs;
an increase of $7 million in selling, general and administrative expenses primarily due to corporate cost reductions in 2020; and
a decrease of $7 million in fractionators and refinery services margin primarily due to a $10 million decrease resulting from a slightly lower average rate achieved due to the increased utilization of our ethane optimization strategy. This decrease was partially offset by a $5 million increase in blending activity at our fractionation facility; partially offset by
an increase of $36 million in terminal services margin primarily due to a $20 million increase in ethane export fees at our Nederland Terminal, an increase of $13 million in loading fees due to higher LPG export volumes at our Nederland Terminal and a $3 million increase at our refined product terminals due to higher throughput and timing of accounting adjustments;
an increase of $20 million in transportation margin primarily due to a $30 million increase due to higher export volumes feeding into our Nederland Terminal, a $6 million increase from higher throughput on our Mariner pipeline system, and a $6 million increase in refined products transportation due to recovery from COVID-19 related demand reduction in the prior period and other refined products demand increases. These increases were partially offset by a $23 million decrease resulting from a slightly lower average rate achieved due to the increased utilization of our ethane optimization strategy; and
an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to an increase primarily resulting from higher throughput on Explorer pipeline due to COVID-19 demand recovery.
Segment Adjusted EBITDA. For the nine months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impacts of the following:
an increase of $98 million in operating expenses primarily due to a $54 million increase in utilities costs, $28 million increase in employee costs resulting primarily from corporate cost reductions in 2020 and an increase of $15 million in allocated corporate overhead costs;
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a decrease of $31 million in marketing margin primarily due to a $29 million decrease in northeast blending and optimization primarily due to realized losses on financial instruments and increased costs related to RINs and intrasegment charges of $28 million which were fully offset within our transportation margin. These decreases were partially offset by a $19 million increase in butane blending margin due to more favorable spreads and additional blending days granted by the EPA due to the Colonial Pipeline shutdown, and an $8 million increase due to inventory and other adjustments in the prior period;
a decrease of $31$45 million in fractionators and refinery services margin primarily due to a $44$48 million increase from higher volumes and higher rates driven by contractual rate escalations tied to broader economic inflationary measures. This increase was partially offset by a decrease from our refinery services business due to a less favorable pricing environment;
an increase of $39 million in transportation margin primarily due to a $62 million increase resulting from downtimehigher y-grade throughput and higher rates driven by contractual rate escalations tied to broader economic inflationary measures on our various fractionators due to Winter Storm Uri in the first quarter of 2021Texas pipeline system, and a slightly lower average rate achieved due to increased utilization of$5 million increase from higher throughput on our ethane optimization strategy. This decrease wasMariner East pipeline system. These increases were partially offset by a $10 million decrease from lower throughput on our Mariner West pipeline due to the timing of customer facility maintenance and a $16 million decrease from intrasegment charges which are fully offset within our marketing and fractionators margin;
an increase of $13 million in terminal services margin primarily due to a $9 million increase from blending activityhigher rates on export volumes loaded at our fractionators facility;Nederland Terminal and a $3 million increase from higher throughput at our Marcus Hook Terminal; and
an increase of $18$9 million in storage margin primarily due to a $4 million increase from the timing of third-party deficiency payments, a $2 million increase in component product storage fees and a $2 million increase from the timing of cavern withdrawals; offset by
a decrease of $114 million in marketing margin primarily due to losses of approximately $128 million from the optimization of NGL component products primarily due to the timing of the recognition of gains on hedged inventory. Associated hedge positions recorded unrealized gains of $125 million during the third quarter of 2022. These decreases were partially offset by an $11 million increase from intrasegment charges which are fully offset within our transportation margin;
an increase of $58 million in operating expenses primarily due to a $43 million increase in gas and power utility costs, a $6 million increase in ad valorem taxes, a $5 million increase in physical product losses and a $3 million increase in maintenance project costs; and
an increase of $6 million in selling, general and administrative expenses primarily due to corporate cost reductionsa $2 million increase in 2020; partially offset byoverhead expenses allocated to the segment, a $1 million increase in employee related costs and a $1 million increase in insurance costs.
Segment Adjusted EBITDA. For the nine months ended September 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
an increase of $76$117 million in fractionators and refinery services margin primarily due to a $123 million increase from higher volumes and higher rates driven by contractual rate escalations tied to broader economic inflationary measures, increased utilization of our ethane optimization strategy in 2022 and a $13 million intrasegment charge, which is fully offset in our transportation margin. These increases were partially offset by a $21 million decrease from a less favorable pricing environment impacting our refinery services business;
an increase of $57 million in transportation margin primarily due to a $76$138 million increase dueresulting from higher throughput and higher rates driven by contractual rate escalations tied to broader economic inflationary measures on our Texas y-grade pipeline system, an $11 million increase from higher exportexported volumes feeding into our Nederland Terminal and a $39$5 million increase resulting from higher throughput on our Mariner pipeline systems, intrasegment revenues of $28 million which are fully offset by a charge reflected in our marketing margin, and a $15 million increase in refined products transportation due to recovery from COVID-19 related demand reduction in the prior period and other refined products demand increases.East pipeline. These increases were partially offset by an $81intrasegment charges of $64 million, which are fully offset within our marketing margin, a $21 million decrease resulting from lower throughput across the various regions in Texason our Mariner West pipeline due to Winter Storm Uri related production outagescustomer maintenance during the current period and a slightly lower average rate achieved due to increased utilization of$13 million intrasegment charge, which is fully offset in our ethane optimization strategy;fractionators margin;
an increase of $60$51 million in terminal services margin primarily due to a $49$35 million increase in ethanefrom higher export feesvolumes loaded at our Nederland Terminal, a $36$14 million increase in loading fees due to higher LPG export volumes at our Nederland Terminal, an $11 million increase due tofrom higher throughput at our Marcus Hook Terminal and a $10$2 million increase from our refined products terminals; and
an increase of $11 million in storage margin primarily due to higher throughputa $12 million increase in fees generated from exported volumes, a $5 million increase from timing of deficiency payments and storage at our refined product terminals due to recoverya $4 million increase from COVID-19 related demand reduction in the prior period and other refined products demand increases.timing of cavern withdrawals. These increases were partially offset by a $44$10 million decrease resultingin component product storage fees; partially offset by

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an increase of $135 million in operating expenses due to a $98 million increase in gas and power utility costs, a $15 million increase in ad valorem taxes, a $10 million increase from an expirationmaintenance project costs, a $5 million increase in physical product losses, a $5 million increase in office expenses and a $2 million increase in employee costs;
a decrease of a third-party contract at$74 million in marketing margin primarily due to losses of approximately $136 million from the optimization of NGL component products primarily due to the timing of the recognition of gains on hedged inventory. Associated hedge positions recorded unrealized gains of $157 million during the nine months ended September 30, 2022. These decreases were partially offset by increased intrasegment charges of $64 million, which are fully offset within our Nederland Terminal in the second quarter of 2020;transportation margin;
an increase of $19$14 million in storage marginselling, general and administrative expenses primarily due to fees generated from exported volumes;a $7 million increase in overhead expenses allocated to the segment, a $3 million increase in employee related costs and a $1 million increase in insurance costs; and
an increasea decrease of $12$4 million in Adjusted EBITDA related to unconsolidated affiliates due to a $7$3 million increase primarily resultingdecrease from higher throughputlower volumes on the Explorer pipeline due to COVID-19 demand recovery and a $5$2 million increasedecrease from higherlower volumes on the White Cliffs pipeline.
Crude Oil Transportation and Services
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
Crude transportation volumes (MBbls/d)Crude transportation volumes (MBbls/d)4,173 3,551 622 3,901 3,840 61 Crude transportation volumes (MBbls/d)4,575 4,173 402 4,369 3,901 468 
Crude terminals volumes (MBbls/d)2,703 2,317 386 2,553 2,688 (135)
Crude terminal volumes (MBbls/d)Crude terminal volumes (MBbls/d)3,080 2,703 377 2,968 2,553 415 
RevenuesRevenues$4,578 $2,850 $1,728 $12,498 $8,877 $3,621 Revenues$6,416 $4,578 $1,838 $19,642 $12,498 $7,144 
Cost of products soldCost of products sold3,918 2,096 1,822 10,520 6,704 3,816 Cost of products sold5,627 3,918 1,709 17,347 10,520 6,827 
Segment marginSegment margin660 754 (94)1,978 2,173 (195)Segment margin789 660 129 2,295 1,978 317 
Unrealized (gains) losses on commodity risk management activitiesUnrealized (gains) losses on commodity risk management activities14 (1)15 12 Unrealized (gains) losses on commodity risk management activities14 (12)(4)12 (16)
Operating expenses, excluding non-cash compensation expenseOperating expenses, excluding non-cash compensation expense(142)(112)(30)(414)(401)(13)Operating expenses, excluding non-cash compensation expense(176)(142)(34)(467)(414)(53)
Selling, general and administrative expenses, excluding non-cash compensation expenseSelling, general and administrative expenses, excluding non-cash compensation expense(44)(28)(16)(102)(82)(20)Selling, general and administrative expenses, excluding non-cash compensation expense(155)(44)(111)(212)(102)(110)
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates(2)15 32 (17)Adjusted EBITDA related to unconsolidated affiliates(6)15 (12)
OtherOther(8)10 (9)Other— (1)— 
Segment Adjusted EBITDASegment Adjusted EBITDA$496 $631 $(135)$1,490 $1,741 $(251)Segment Adjusted EBITDA$461 $496 $(35)$1,616 $1,490 $126 
Volumes. For the three and nine months ended September 30, 20212022 compared to the same periodperiods last year, crude transportation volumes were higher on our Texas pipeline system and Bakken pipeline,Pipeline, driven by a recovery incontinuing crude oil production growth in these regions as
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a result of higher crude oil prices and refinery demand. Additionally, volumes benefited from assets acquired in 2021 as well as a recovery in refinery utilization.new assets placed into service, primarily Cushing South and Ted Collins Link. Volumes on our Bayou Bridge pipeline were also higher, driven by more favorableprimarily due to increased crude oil differentials for shippers. Volumes also benefitedsupply from a full quarter of operations from our Cushing South pipeline.recent Strategic Petroleum Reserve sales. Crude terminalTerminal volumes were higher due to increased customerStrategic Petroleum Reserve sale volumes increasing throughput and export activity at our Gulf Coast terminals.
For the nine months ended September 30, 2021 compared to the same period last year, crude transportation volumes were higher on our Bakken pipeline and Bayou Bridge pipelines, reflecting the continued recovery in crude oil production in North Dakota and more favorable crude oil differentials for shippers on Bayou Bridge. Volumes on our Texas pipeline system were slightly lower, primarily reflecting adverse weather negatively impacting volumes in the first quarter of 2021 and less favorable spreads for shippers to some markets in 2021. Crude terminal volumes were lower primarily due to reduced export demand.
Segment Adjusted EBITDA. For the three months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following:
a decreasean increase of $79$117 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $133$36 million decrease from our crude oil acquisition and marketing businessincrease due to storage trading gains realized in the prior period, unfavorable crude inventory valuation adjustments, and less favorable pricing conditions impactinghigher volumes on our Bakken Pipeline, a $28 million increase related to Gulf Coast trading operations,assets acquired in 2021, a $6$45 million decreaseincrease in throughput at our crudeGulf Coast terminals primarily driven by lowerdue to Strategic Petroleum Reserve volumes, stronger refinery utilization and higher export demand, a $6 million increase on our Bayou Bridge pipeline due to higher volumes and a $3$5 million decrease fromincrease on our Texas crude pipeline system due to lower average tariff rates realized; partiallyhigher volumes; offset by a $65 million increase from improved performance on our Bayou Bridge and Bakken pipelines;
an increase of $30$34 million in operating expenses primarily due to higher volume-driven expenses, higher project expenses and higher employee expenses;expenses related to assets acquired in 2021;

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an increase of $16$111 million in selling, general and administrative expenses primarily due to a charge related to a legal expenses and higher overhead allocations to the crude segment as a result of assets acquired;matter; and
a decrease of $2$6 million in Adjusted EBITDA related to unconsolidated affiliates due to lower volumes on White Cliffs pipeline from lower crude oil production, partially offset by an increase in jet fuel sales by our joint ventures.the consolidation of certain operations that were previously reflected as unconsolidated affiliates.
Segment Adjusted EBITDA. For the nine months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreasedincreased due to the net impacts of the following:
a decreasean increase of $192$301 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $152$177 million decreaseincrease due to higher volumes on our Bakken Pipeline, a $63 million increase related to assets acquired in 2021, a $61 million increase in throughput at our Gulf Coast terminals due to Strategic Petroleum Reserve volumes, stronger refinery utilization and higher export demand, a $17 million increase from our Texas crude pipeline system due to lower utilizationhigher volumes and lower average tariff rates realized, a $58$10 million increase due to higher volumes on our Bayou Bridge pipeline, partly offset by a $20 million decrease from our crude oil acquisition and marketing business primarily due to storage trading gains realized in the prior period and less favorable pricing conditions impacting our Bakken to Gulf Coast trading operations and unfavorable inventory valuation adjustments from crude oil prices; partially offset by favorable crude inventory valuation adjustments and a $34 million decrease in throughput at our crude terminals primarily driven by reduced export demand; partially offset by an $18 million increase due to higher volumes on our Bayou Bridge pipeline and a $37 million increase due to higher volumes on our Bakken Pipeline;
an increase of $13$53 million in operating expenses primarily due to higher volume-driven expenses, higher project expenses and higher employee expenses;expenses related to assets acquired in 2021;
an increase of $20$110 million in selling, general and administrative expenses primarily due to a charge related to a legal expenses and higher overhead allocations to the crude segment as a result of assets acquired;matter; and
a decrease of $17$12 million in Adjusted EBITDA related to unconsolidated affiliates due to lower volumes on White Cliffs pipeline from lower crude oil production, partially offset by an increase in jet fuel sales by our joint ventures.
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Tablethe consolidation of Contentscertain operations that were previously reflected as unconsolidated affiliates.
Investment in Sunoco LP
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
RevenuesRevenues$4,779 $2,805 $1,974 $12,642 $8,157 $4,485 Revenues$6,594 $4,779 $1,815 $19,811 $12,642 $7,169 
Cost of products soldCost of products sold4,472 2,497 1,975 11,631 7,383 4,248 Cost of products sold6,261 4,472 1,789 18,703 11,631 7,072 
Segment marginSegment margin307 308 (1)1,011 774 237 Segment margin333 307 26 1,108 1,011 97 
Unrealized (gains) losses on commodity risk management activitiesUnrealized (gains) losses on commodity risk management activities(6)(5)— (5)Unrealized (gains) losses on commodity risk management activities23 21 (5)
Operating expenses, excluding non-cash compensation expenseOperating expenses, excluding non-cash compensation expense(85)(84)(1)(236)(265)29 Operating expenses, excluding non-cash compensation expense(98)(85)(13)(293)(236)(57)
Selling, general and administrative expenses, excluding non-cash compensation expenseSelling, general and administrative expenses, excluding non-cash compensation expense(23)(24)(67)(76)Selling, general and administrative expenses, excluding non-cash compensation expense(29)(23)(6)(78)(67)(11)
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates— Adjusted EBITDA related to unconsolidated affiliates(1)— 
Inventory valuation adjustmentsInventory valuation adjustments(9)(11)(168)126 (294)Inventory valuation adjustments40 (9)49 (81)(168)87 
OtherOther(1)14 14 — Other15 14 
Segment Adjusted EBITDASegment Adjusted EBITDA$198 $189 $$556 $580 $(24)Segment Adjusted EBITDA$276 $198 $78 $681 $556 $125 
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impacts of the following:
an increase in the gross profit on motor fuel sales of $4$75 million primarily due to a 6.4%23.6% increase in gallons sold, partially offset by a 7.3% decrease in gross profit per gallon sold and a 0.8% increase in gallons sold; and
an increase in non-motor fuel salesgross profit of $5$22 million primarily due to the recent acquisition of refined product terminals, as well as increased credit card transactions and merchandise gross profitprofit; partially offset by

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an increase in operating expenses and franchise fee income.selling, general and administrative expenses of $19 million primarily due to the recent acquisitions of refined product terminals and a transmix processing and terminal facility, higher employee costs, insurance costs and credit card processing fees.
Segment Adjusted EBITDA.For the nine months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment decreasedincreased due to the net impacts of the following:
a decreasean increase in the gross profit on motor fuel sales of $62$126 million primarily due to a 14.8% decrease17.3% increase in gross profit per gallon sold partially offset byand a 7.5%1.4% increase in gallons sold; and
an increase in non-motor fuel gross profit of $67 million primarily due to the recent acquisition of refined product terminals, as well as increased credit card transactions and merchandise gross profit; partially offset by
a decreasean increase in operating expenses and selling, general and administrative expenses of $38$68 million primarily due to lowerhigher costs as a result of the 2021 fourth quarter acquisition of refined product terminals and the transmix processing and terminal facility, higher employee costs, ofcredit card processing fees, utilities costs, maintenance costs and lower expected credit losses.insurance costs.
Investment in USAC
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
RevenuesRevenues$159 $161 $(2)$473 $509 $(36)Revenues$179 $159 $20 $514 $473 $41 
Cost of products soldCost of products sold19 20 (1)61 62 (1)Cost of products sold28 19 78 61 17 
Segment marginSegment margin140 141 (1)412 447 (35)Segment margin151 140 11 436 412 24 
Operating expenses, excluding non-cash compensation expenseOperating expenses, excluding non-cash compensation expense(31)(27)(4)(83)(92)Operating expenses, excluding non-cash compensation expense(31)(31)— (90)(83)(7)
Selling, general and administrative expenses, excluding non-cash compensation expenseSelling, general and administrative expenses, excluding non-cash compensation expense(10)(10)— (30)(40)10 Selling, general and administrative expenses, excluding non-cash compensation expense(11)(10)(1)(33)(30)(3)
Segment Adjusted EBITDASegment Adjusted EBITDA$99 $104 $(5)$299 $315 $(16)Segment Adjusted EBITDA$109 $99 $10 $313 $299 $14 
The Investment in USAC segment reflects the consolidated results of USAC.
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Segment Adjusted EBITDA. For the three months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment decreasedincreased primarily due to the following:
a decreasean increase of $1$11 million in segment margin primarily due to slightly lower revenue generating horsepower; and
an increase of $4 million in operating expenses primarily due to an increase in property taxescontract operations revenue as a result of select price increases on USAC’s existing fleet under contract and expenses related to our vehicle fleet.higher revenue generating horsepower.
Segment Adjusted EBITDA.For the nine months ended September 30, 20212022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment decreasedincreased primarily due to the net impacts of the following:
a decreasean increase of $35$24 million in segment margin primarily due to loweran increase in contract operations revenue as a result of select price increases on USAC’s existing fleet under contract, higher revenue generating horsepower;horsepower and an increase in parts and service revenue related to an increase in maintenance work performed on units; partially offset by
a decreasean increase of $9$7 million in operating expenses primarily driven by a $7 million decreasedue to an increase in outside maintenance costs due to greater use and higher costs of third-party labor, an increase in USAC’s vehicle fleet expenses, an increase in direct labor costs due to higher employee costs in the current period, an increase in retail parts and services expenses and a $4 million decrease primarilyan increase due to sales tax refunds received in 2021; andthe prior period.

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a decreaseTable of $10 million in selling, general and administrative expenses primarily due to a $6 million decrease in the provision for expected credit losses, a $2 million decrease in severance charges related to the departure of an executive and a $2 million decrease in employee-related expenses.Contents
All Other
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months Ended
September 30,
Nine Months Ended
September 30,
20212020Change20212020Change20222021Change20222021Change
RevenuesRevenues$696 $367 $329 $2,784 $1,372 $1,412 Revenues$1,084 $696 $388 $2,761 $2,784 $(23)
Cost of products soldCost of products sold652 318 334 2,464 1,110 1,354 Cost of products sold1,052 652 400 2,548 2,464 84 
Segment marginSegment margin44 49 (5)320 262 58 Segment margin32 44 (12)213 320 (107)
Unrealized losses on commodity risk management activitiesUnrealized losses on commodity risk management activities— Unrealized losses on commodity risk management activities13 12 
Operating expenses, excluding non-cash compensation expenseOperating expenses, excluding non-cash compensation expense(29)(35)(118)(100)(18)Operating expenses, excluding non-cash compensation expense(17)(29)12 (75)(118)43 
Selling, general and administrative expenses, excluding non-cash compensation expenseSelling, general and administrative expenses, excluding non-cash compensation expense(13)(23)10 (71)(80)Selling, general and administrative expenses, excluding non-cash compensation expense(11)(13)(44)(71)27 
Adjusted EBITDA related to unconsolidated affiliatesAdjusted EBITDA related to unconsolidated affiliates— Adjusted EBITDA related to unconsolidated affiliates— 
Other and eliminationsOther and eliminations27 (19)13 (21)34 Other and eliminations11 40 13 27 
Segment Adjusted EBITDASegment Adjusted EBITDA$18 $22 $(4)$153 $62 $91 Segment Adjusted EBITDA$30 $18 $12 $149 $153 $(4)
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, which include natural gas gathering and processing assets.until those assets were divested in August 2022.
Segment Adjusted EBITDA. For the three months ended September 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased primarily due to the net impacts of the following:
a decrease of $12 million due to the settlement of customer disputes related to prior period activity;
a decrease of $7 million due to the revaluation of natural gas inventory; and
a decrease of $2 million due to lower trading gains; partially offset by
an increase of $5 million due to higher compressor sales and lower operating expenses in our compressor business;
an increase of $2 million from Energy Transfer Canada due to the aggregate impact of multiples smaller changes; and
an increase of $2 million due to lower utility expense.
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Segment Adjusted EBITDA. For the nine months ended September 30, 20212022 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:
an increase of $60 million from power trading activities primarily due to short-term, favorable market conditions created by Winter Storm Uri in February of 2021;
an increase of $17 million primarily due to revenues earned by our dual drive compression business under the Electric Reliability Council of Texas (“ERCOT”) responsive reserve program during Winter Storm Uri;
• an increase of $11$18 million due to improved margins at our dual drive compression business resulting from morea favorable market pricing conditions;environment for physical gas trading and storage activities;
an increase of $12 million due to lower mergera favorable environment for our power trading activities; and acquisition expenses;
an increase of $6 million from Energy Transfer Canada due to the aggregate impact of multiples smaller changes;
an increase of $2 million due to a contract expirationhigher coal royalties at our natural resources business in 2020; and
an increase of $2 million due to higher compressor sales and lower operating expenses in our compressor business; partially offset by
a decrease of $22$17 million from 2020 insurance proceeds received on settled claimsdue to the sale of Energy Transfer Canada.
Segment Adjusted EBITDA. For the nine months ended September 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our MTBE litigation.all other segment decreased primarily due to the net impacts of the following:
a decrease of $68 million due to gains in the prior period related to Winter Storm Uri; partially offset by
an increase of $18 million due to a favorable environment for physical gas trading and storage activities;
an increase of $17 million due to higher merger and acquisition expense in the prior period;
a decrease of $13 million in ad valorem taxes;
an increase of $12 million due to a favorable environment for our power trading activities; and
an increase of $12 million due to higher coal royalties at our natural resources business.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Our ability to satisfy obligations and pay distributions to unitholders will depend on our 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.

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We currently expect capital expenditures in 20212022 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):
GrowthMaintenanceGrowthMaintenance
LowHighLowHighLowHighLowHigh
Intrastate transportation and storageIntrastate transportation and storage$15 $25 $30 $35 Intrastate transportation and storage$120 $145 $40 $45 
Interstate transportation and storage (1)
Interstate transportation and storage (1)
50 75 115 120 
Interstate transportation and storage (1)
475 525 160 170 
MidstreamMidstream445 470 115 120 Midstream700 830 145 155 
NGL and refined products transportation and servicesNGL and refined products transportation and services650 725 110 120 NGL and refined products transportation and services375 425 125 135 
Crude oil transportation and services (1)
Crude oil transportation and services (1)
275 325 90 100 
Crude oil transportation and services (1)
120 155 105 110 
All other (including eliminations)All other (including eliminations)90 115 45 55 All other (including eliminations)10 20 40 50 
Total capital expendituresTotal capital expenditures$1,525 $1,735 $505 $550 Total capital expenditures$1,800 $2,100 $615 $665 
(1)Includes capital expenditures related to our proportionate ownershipshare of the Bakken, Rover and Bayou Bridge pipeline projects and our proportionate ownership ofjoint ventures, as well as the Orbit Gulf Coast NGL export project.Exports joint venture.
The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we have included these factors in our anticipated growth capital expenditures for each year.
We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally expect to fund growth capital expenditures with proceeds of borrowings under our credit facilities, along with cash from operations.
Sunoco LP currently expects to invest approximately $150 million in growth capital expenditures and approximately $45$50 million on maintenance capital expenditures for the full year 2021.2022.
USAC currently plans to spend approximately $20$26 million in maintenance capital expenditures and currently has budgetedspend between $30$120 million and $40$130 million in expansion capital expenditures for the full year 2021.
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2022.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations”), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash 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, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers.
Nine months ended September 30, 20212022 compared to nine months ended September 30, 20202021. Cash provided by operating activities during 20212022 was $9.42$7.71 billion compared to $5.46 billion for 2020, and net income was $5.46$9.42 billion for 2021, and net lossincome was $693 million$4.43 billion for 2020.2022 and $5.46 billion for 2021. The difference between net income and net cash provided by operating activities for the nine months ended September 30, 20212022 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions)acquisitions and divestitures) of $970$212 million and other non-cash items totaling $2.79$3.35 billion.

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The non-cash activity in 20212022 and 20202021 consisted primarily of depreciation, depletion and amortization of $2.84$3.10 billion and $2.72$2.84 billion, respectively, non-cash compensation expense of $81$88 million and $93$81 million, respectively, favorable inventory valuation adjustments of $168$81 million and unfavorable inventory valuation adjustments of $126$168 million, respectively, deferred income taxes of $199$158 million and $159 million, respectively, losses on extinguishments of debt of $8 million and $62$199 million, respectively, and impairment losses of $11$386 million and $2.80 billion,$11 million, respectively. Non-cash activity also included equity in earnings of unconsolidated affiliates of $186 million and $191 million in 2022 and $46 million in 2021, and 2020, respectively, and impairmentrespectively. In 2021, we also had losses on extinguishments of investment in an unconsolidated affiliatedebt of $129 million in 2020.$8 million.
Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $182 million in 2022 and $226 million in 2021 and $176 million in 2020.2021.
Cash paid for interest, net of interest capitalized, was $1.57$1.48 billion and $1.47$1.57 billion for the nine months ended September 30, 20212022 and 2020,2021, respectively. Interest capitalized was $97$84 million and $163$97 million for the nine months ended September 30, 20212022 and 2020,2021, respectively.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash contributions 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.
Nine months ended September 30, 20212022 compared to nine months ended September 30, 2020.2021. Cash used in investing activities during 20212022 was $1.91$3.08 billion compared to $3.86$1.91 billion for 2020.2021. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 20212022 were $2.02$2.44 billion compared to $3.97$2.02 billion for 2020.2021. Additional detail related to our capital expenditures is provided in the table below. In 2022, we paid
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Table$485 million in cash for the acquisitions of ContentsWoodford Express, LLC, we paid $325 million in cash for the acquisition of Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC) and Sunoco LP paid
$252 million in cash related to its acquisition of a transmix processing and terminal facility. In 2022, we received $302 million in cash from the sale of our interest in Energy Transfer Canada.
The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover, and Bayou Bridge, pipeline projects and Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs) on an accrual basis for the nine months ended September 30, 2021:2022:
Capital Expenditures Recorded During PeriodCapital Expenditures Recorded During Period
GrowthMaintenanceTotalGrowthMaintenanceTotal
Intrastate transportation and storageIntrastate transportation and storage$17 $24 $41 Intrastate transportation and storage$75 $37 $112 
Interstate transportation and storageInterstate transportation and storage24 72 96 Interstate transportation and storage383 123 506 
MidstreamMidstream272 74 346 Midstream512 129 641 
NGL and refined products transportation and servicesNGL and refined products transportation and services508 77 585 NGL and refined products transportation and services220 83 303 
Crude oil transportation and servicesCrude oil transportation and services208 61 269 Crude oil transportation and services115 81 196 
Investment in Sunoco LPInvestment in Sunoco LP70 22 92 Investment in Sunoco LP76 21 97 
Investment in USACInvestment in USAC26 15 41 Investment in USAC99 20 119 
All other (including eliminations)All other (including eliminations)48 26 74 All other (including eliminations)19 33 52 
Total capital expendituresTotal capital expenditures$1,173 $371 $1,544 Total capital expenditures$1,499 $527 $2,026 
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.
Nine months ended September 30, 20212022 compared to nine months ended September 30, 2020.2021. Cash used in financing activities during 20212022 was $7.57$4.65 billion compared to $1.61$7.57 billion for 2020.2021. During 2021,2022, we had a net decrease in our debt level of $6.00$1.71 billion compared to a net increasedecrease of $358 million$6.00 billion for 2020. In 2021 and 2020, we paid debt issuance costs2021.

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Table of $3 million and $53 million, respectively. During 2021, we received $889 million from offerings of preferred units, and during 2020, our subsidiaries received $1.58 billion from offerings of preferred units.Contents
In 20212022 and 2020,2021, we paid distributions of $1.38$2.12 billion and $2.40$1.38 billion, respectively, to our partners. In 20212022 and 2020,2021, we paid distributions of $1.15$1.18 billion and $1.28$1.15 billion, respectively, to noncontrolling interests. In 20212022 and 2020,2021, we paid distributions of $37 million to our redeemable noncontrolling interests. In addition,2022 and 2021, we paid debt issuance costs of $9 million and $3 million, respectively.
In 2022 and 2021, we received capital contributions of $404 million and $114 million, respectively, in cash from noncontrolling interests ininterests. During 2021, compared to $203we received $889 million in cash from noncontrolling interests in 2020.
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preferred units.
Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
ET Indebtedness:
Senior Notes (1)
$36,454 $37,855 
Term Loan (2)
— 2,000 
Energy Transfer Indebtedness:Energy Transfer Indebtedness:
Notes and Debentures (3)
Notes and Debentures (3)
$36,733 $37,733 
Five-Year Credit Facility (2)
Five-Year Credit Facility (2)
599 3,103 
Five-Year Credit Facility (2)
2,645 2,937 
Subsidiary Indebtedness:Subsidiary Indebtedness:Subsidiary Indebtedness:
Transwestern Senior NotesTranswestern Senior Notes400 400 Transwestern Senior Notes250 400 
Panhandle Senior Notes235 235 
Panhandle Notes and DebenturesPanhandle Notes and Debentures235 235 
Bakken Senior Notes (3)(1)
Bakken Senior Notes (3)(1)
2,500 2,500 
Bakken Senior Notes (3)(1)
1,850 2,500 
Sunoco LP Senior Notes and lease-related obligationsSunoco LP Senior Notes and lease-related obligations2,701 3,139 Sunoco LP Senior Notes and lease-related obligations2,694 2,700 
USAC Senior NotesUSAC Senior Notes1,475 1,475 USAC Senior Notes1,475 1,475 
HFOTCO Tax Exempt NotesHFOTCO Tax Exempt Notes225 225 HFOTCO Tax Exempt Notes225 225 
Revolving credit facilities:Revolving credit facilities:Revolving credit facilities:
Sunoco LP Credit FacilitySunoco LP Credit Facility250 — Sunoco LP Credit Facility704 581 
USAC Credit FacilityUSAC Credit Facility506 474 USAC Credit Facility618 516 
Energy Transfer Canada Revolving Credit Facility(2)Energy Transfer Canada Revolving Credit Facility(2)81 57 Energy Transfer Canada Revolving Credit Facility(2)— 
Energy Transfer Canada Term Loan A252 261 
Energy Transfer Canada KAPS Facility51 — 
Energy Transfer Canada KAPS Facility (2)
Energy Transfer Canada KAPS Facility (2)
— 142 
Energy Transfer Canada Term Loan A (2)
Energy Transfer Canada Term Loan A (2)
— 249 
Other long-term debtOther long-term debtOther long-term debt
Net unamortized premiums, discounts, and fair value adjustmentsNet unamortized premiums, discounts, and fair value adjustments(14)(10)Net unamortized premiums, discounts, and fair value adjustments199 238 
Deferred debt issuance costsDeferred debt issuance costs(248)(279)Deferred debt issuance costs(216)(239)
Total debtTotal debt45,471 51,438 Total debt47,415 49,702 
Less: current maturities of long-term debtLess: current maturities of long-term debt678 21 Less: current maturities of long-term debt680 
Long-term debt, less current maturitiesLong-term debt, less current maturities$44,793 $51,417 Long-term debt, less current maturities$47,413 $49,022 
(1)The balances presented above include senior notes that were formerly obligations of ETO prior to the Rollup Mergers discussed below and in “Recent Developments” above. As of MarchFor December 31, 2021, and December 31, 2020, the outstanding principal amount of ETO senior notes was $36.4 billion and $37.8 billion, respectively. Beginning April 1, 2021, these senior notes are obligations of ET. A description of the ETO senior notes that were assumed by ET is included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020.
(2)The Term Loan and Five-Year Credit Facility were previously obligations of ETO. Subsequent to the completion of the Rollup Mergers on April 1, 2021, these facilities are obligations of ET.
(3)Thethis balance includes $650 million aggregate principal amount of 3.625% Senior Notes due April 2022 included in current maturities of long-term debtdebt. These notes were repaid in April 2022.
(2)These facilities were included in the August 2022 Energy Transfer Canada divestiture as discussed in Note 2 to our consolidated financial statements in “Item 1. Financial Statements.”
(3)As of September 30, 2021.2022, this balance included a total of $2.65 billion aggregate principal amount of senior notes due on or before September 30, 2023, which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
Senior Notes - Recent Transactions
In connection with the Rollup Mergers on April 1, 2021, ET entered into various supplemental indentures and assumed all the obligations of ETO under the respective indentures and credit agreements.
During the second quarter of 2021, ET repaid $1.5 billion on the Term Loan in part through proceeds from its Series H Preferred Unit issuance. During the third quarter of 2021,February 2022, the Partnership repaid the remaining $500 million balance and terminated the Term Loan.
During the first quarter of 2021, ETO redeemed its $600$300 million aggregate principal amount of 4.40% senior notesits 4.65% Senior Notes due February 2022 using proceeds from its Five-Year Credit Facility (defined below).
In April 1, 2021 and its $8002022, Dakota Access redeemed $650 million aggregate principal amount of 4.65% senior notes3.625% Senior Notes due June 1, 2021,April 2022 using proceeds from contributions made by its members. The Partnership indirectly owns 36.4% of the Five-Year Credit Facility.ownership interests in Dakota Access.
During

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In August 2022, the third quarter of 2021, ET issuedPartnership exercised its par call notices to redeem in full its $1.0 billion aggregate principal amount of 5.2% senior notes due February 1, 2022,option and $900fully redeemed $700 million aggregate principal amount of 5.875% senior notesits 5.00% Senior Notes due March 1, 2022.
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The Partnership expects to redeem both series of senior notes during the fourth quarter of 2021, utilizingOctober 2022 with proceeds from its Five-Year Credit Facility.
On October 20, 2021, Sunoco LP completed a private offering of $800 million in aggregate principal amount of 4.500% senior notes due 2030 (the “2030 Notes”). Sunoco LP used the proceeds from the private offering to fund a tender offer and repurchase all of its senior notes due 2026.
Credit Facilities and Commercial Paper
Term Loan
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO’s obligations in respect of its term loan credit agreement (the “Term Loan”) and Sunoco Logistics Operations was released as a guarantor in respect of the Term Loan. The Partnership’s Term Loan provides for a $2.00 billion three-year term loan credit facility. During the third quarter of 2021, the Term Loan was repaid in full and terminated.
Five-Year Credit Facility
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO’s obligations in respect of itsThe Partnership’s revolving credit facility (the “Five-Year Credit Facility”) and Sunoco Logistics Operations was released as a guarantor in respect of the Five-Year Credit Facility. The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2024.April 11, 2027. The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00$7.00 billion under certain conditions.
As of September 30, 2021,2022, the Five-Year Credit Facility had $599 million$2.65 billion of outstanding borrowings, of which $590$825 million consisted of commercial paper. The amount available for future borrowings was $4.37$2.32 billion, after accounting for outstanding letters of credit in the amount of $31$38 million. The weighted average interest rate on the total amount outstanding as of September 30, 20212022 was 0.43%4.29%.
364-Day Facility
As a result of the Rollup Mergers, on April 1, 2021, ET assumed all of ETO’s obligations in respect of its 364-day revolving credit facility (the “364-Day Facility”) and Sunoco Logistics Operations was released as a guarantor in respect of the 364-Day Facility. The Partnership’s 364-Day Facility allows for unsecured borrowings up to $1.00 billion and matures on November 26, 2021. As of September 30, 2021, the 364-Day Facility had no outstanding borrowings.
Sunoco LP Credit Facility
As of September 30, 2021, the2022, Sunoco LP Credit FacilityLP’s credit facility had $250$704 million of outstanding borrowings and $6$7 million in standby letters of credit and, as amended in April 2022, matures in July 2023.April 2027. The amount available for future borrowings at September 30, 20212022 was $1.24 billion.$789 million. The weighted average interest rate on the total amount outstanding as of September 30, 20212022 was 2.09%5.11%.
USAC Credit Facility
As of September 30, 2021, USAC2022, USAC’s credit facility had $506$618 million of outstanding borrowings under the credit agreement.and no outstanding letters of credit. As of September 30, 2021,2022, USAC had $1.09 billion$982 million of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $114$287 million. The weighted average interest rate on the total amount outstanding as of September 30, 20212022 was 2.96%5.54%.
Energy Transfer Canada Credit Facilities
As of September 30, 2021, the Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility had outstanding borrowings of C$320 million and C$103 million, respectively (US$252 million and US$81 million, respectively, at the September 30, 2021 exchange rate). As of September 30, 2021, the KAPS Facility had outstanding borrowings of C$65 million (US$51 million at the September 30, 2021 exchange rate).
Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations and covenants related to our debt agreements as of September 30, 2021.2022.
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CASH DISTRIBUTIONS
Cash Distributions Paid by ETEnergy Transfer
Under its partnership agreement, ETEnergy Transfer will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriateGeneral Partner to provide for future cash requirements.
Cash Distributions on ETEnergy Transfer Common Units
Distributions declared and/or paid with respect to ETEnergy Transfer common units subsequent to December 31, 20202021 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 20202021February 8, 20212022February 19, 202118, 2022$0.15250.1750 
March 31, 20212022May 11, 20219, 2022May 19, 202120220.15250.2000 
June 30, 20212022August 6, 20218, 2022August 19, 202120220.15250.2300 
September 30, 20212022November 5, 20214, 2022November 19, 202121, 20220.15250.2650 

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Cash Distributions on ETEnergy Transfer Preferred Units
As discussed in “Recent Developments”, in connection with the Rollup Mergers, ETO’s outstanding preferred units were converted into ET Preferred Units.
Distributions declared on the ETEnergy 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)
March 31, 2021May 3, 2021May 17, 2021$— $— $0.4609 $0.4766 $0.4750 $33.75 $35.625 $— 
June 30, 2021August 2, 2021August 16, 202131.25 33.125 0.4609 0.4766 0.4750 — — — 
September 30, 2021November 1, 2021November 15, 2021— — 0.4609 0.4766 0.4750 33.75 35.625 27.08 (2)
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, 2021February 1, 2022February 15, 2022$31.250 $33.125 $0.4609 $0.4766 $0.475 $— $— $— 
March 31, 2022May 2, 2022May 16, 2022— — 0.4609 0.4766 0.475 33.750 35.625 32.500 
June 30, 2022August 1, 2022August 15, 202231.250 33.125 0.4609 0.4766 0.475 — — — 
September 30, 2022November 1, 2022November 15, 2022— — 0.4609 0.4766 0.4750 33.75 35.625 32.50 
(1)Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.
(2)Represents initial prorated distribution.
Description of ETEnergy Transfer Preferred Units
A summary of the distribution and redemption rights associated with the ETEnergy Transfer Preferred Units is included in Note 9 in “Item 1. Financial Statements.”
Cash Distributions Paid by Subsidiaries
The Partnership’s consolidated financial statements include Sunoco LP and USAC, both of which are publicly traded master limited partnerships, as well as other less-than-wholly-owned,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 (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter.
Cash Distributions Paid by Sunoco LP
Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, 20202021 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 20202021February 8, 20212022February 19, 202118, 2022$0.8255 
March 31, 20212022May 11, 20219, 2022May 19, 202120220.8255 
June 30, 20212022August 6, 20218, 2022August 19, 202120220.8255 
September 30, 20212022November 5, 20214, 2022November 19, 202118, 20220.8255 
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Cash Distributions Paid by USAC
Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 20202021 were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 20202021January 25, 202124, 2022February 5, 20214, 2022$0.525 
March 31, 20212022April 26, 202125, 2022May 7, 20216, 20220.525 
June 30, 20212022July 26, 202125, 2022August 6, 20215, 20220.525 
September 30, 20212022October 25, 202124, 2022November 5, 20214, 20220.525 
ESTIMATES AND CRITICAL ACCOUNTING POLICIESESTIMATES
The selection and application ofPartnership’s critical accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existingestimates are described in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership’sits Annual Report on Form 10-K filed with the SEC on February 19, 2021.
RECENT ACCOUNTING PRONOUNCEMENTS
Currently, there are no accounting pronouncements that18, 2022. No significant changes have been issued, but not yet adopted, that are expectedoccurred subsequent to have a material impact on the Partnership’s financial position or results of operations.Form 10-K filing.
FORWARD-LOOKING STATEMENTS
This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements

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are identified as any statement that does not relate strictly to historical or current facts. When used in this 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 identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
the volumes transported on our pipelines and gathering systems;
the level of throughput in our processing and treating facilities;
the fees we charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
the prices and market demand for, and the relationship between, natural gas and NGLs;
energy prices generally;
impacts of world health events, including the COVID-19 pandemic;pandemic, escalating global trade tensions and the conflict between Russia and Ukraine and resulting expansion of sanctions and trade restrictions;
general economic conditions, including sustained periods of inflation and associated central bank monetary policies;
the possibility of cyber and malware attacks;
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;
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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 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 pipelines and facilities;
the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments;
the nonpayment or nonperformance by our customers;
regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;

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risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
the availability and cost of capital and our 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 we own less than a controlling interests, including risks related to management actions at such entities that we may not be able to control or exert influence;
the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations;
the costs and effects of legal and administrative proceedings; and
the risks associated with a potential failure to successfully combine our business with that of Enable.
You should not put undue reliance on 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, 20202021 filed with the SEC on February 19, 2021 and “Part II - Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 filed with the SEC on August 5, 2021.18, 2022. 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 the Partnership’s Annual Report on Form 10-K for the year ended December 31, 20202021 filed with the SEC on February 19, 2021,18, 2022, 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, 2020.2021. Since December 31, 2020,2021, there have been no material changes to our primary market risk exposures or how those exposures are managed.
Commodity Price Risk
The 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. Dollar amounts are presented in millions.
September 30, 2021December 31, 2020September 30, 2022December 31, 2021
Notional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% ChangeNotional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% ChangeNotional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% ChangeNotional VolumeFair Value Asset (Liability)Effect of Hypothetical 10% Change
Mark-to-Market DerivativesMark-to-Market DerivativesMark-to-Market Derivatives
(Trading)(Trading)(Trading)
Natural Gas (BBtu):Natural Gas (BBtu):Natural Gas (BBtu):
Fixed Swaps/FuturesFixed Swaps/Futures763 $— $— 585 $— $— 
Basis Swaps IFERC/NYMEX (1)
Basis Swaps IFERC/NYMEX (1)
(81,963)$10 $(44,225)$$
Basis Swaps IFERC/NYMEX (1)
73,363 16 (66,665)(5)
Fixed Swaps/Futures475 — 1,603 — — 
Power (Megawatt):Power (Megawatt):Power (Megawatt):
ForwardsForwards712,400 15 — 1,392,400 — Forwards455,200 653,000 — 
FuturesFutures(640,800)(7)— 18,706 (1)— Futures(281,905)(2)(604,920)
Options – PutsOptions – Puts290,400 — — 519,071 — — Options – Puts119,200 — — (7,859)— — 
Options – CallsOptions – Calls36,704 (1)— 2,343,293 — Options – Calls(67,200)(1)— (30,932)— — 
(Non-Trading)(Non-Trading)(Non-Trading)
Natural Gas (BBtu):Natural Gas (BBtu):Natural Gas (BBtu):
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX(8,893)(3)— (29,173)— Basis Swaps IFERC/NYMEX36,443 (17)6,738 
Swing Swaps IFERCSwing Swaps IFERC(48,675)11,208 (2)— Swing Swaps IFERC(217,515)24 (106,333)32 31 
Fixed Swaps/FuturesFixed Swaps/Futures(45,588)(55)25 (53,575)31 Fixed Swaps/Futures(31,383)(37)22 (63,898)(24)38 
Forward Physical ContractsForward Physical Contracts(10,071)— (11,861)Forward Physical Contracts(27,603)14 (5,950)— 
NGLs (MBbls) – Forwards/SwapsNGLs (MBbls) – Forwards/Swaps2,785 20 44 (5,840)(100)39 NGLs (MBbls) – Forwards/Swaps4,832 176 70 8,493 12 19 
Crude (MBbls) – Forwards/SwapsCrude (MBbls) – Forwards/Swaps3,732 12 3,672 13 
Refined Products (MBbls) – FuturesRefined Products (MBbls) – Futures(3,272)(3)30 (2,765)(8)Refined Products (MBbls) – Futures(2,604)30 (3,349)(15)32 
Crude (MBbls) – Forwards/Swaps1,693 (13)11 — — — 
Fair Value Hedging DerivativesFair Value Hedging DerivativesFair Value Hedging Derivatives
(Non-Trading)(Non-Trading)(Non-Trading)
Natural Gas (BBtu):Natural Gas (BBtu):Natural Gas (BBtu):
Basis Swaps IFERC/NYMEXBasis Swaps IFERC/NYMEX(21,255)— (30,113)(1)— Basis Swaps IFERC/NYMEX(34,183)13 (40,533)— 
Fixed Swaps/FuturesFixed Swaps/Futures(21,255)(20)12 (30,113)(6)Fixed Swaps/Futures(34,183)24 24 (40,533)41 14 
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the 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, 2021,2022, we and our subsidiaries had $2.51$4.79 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $25$48 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, (dollars in millions), none of which are designated as hedges for accounting purposes:purposes (dollar amounts presented in millions):
TermTerm
Type(1)
Notional Amount OutstandingTerm
Type(1)
Notional Amount Outstanding
September 30,
2021
December 31,
2020
September 30,
2022
December 31,
2021
July 2021(2)(3)
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate$— $400 
July 2022(2)
July 2022(2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate400 400 
July 2022(2)
Forward-starting to pay an average fixed rate of 3.80% and receive a floating rate$— $400 
July 2023(2)
July 2023(2)
Forward-starting to pay a fixed rate of 3.78% and receive a floating rate200 — 
July 2023(2)
Forward-starting to pay an average fixed rate of 3.845% and receive a floating rate400 200 
July 2024(2)
July 2024(2)
Forward-starting to pay a fixed rate of 3.88% and receive a floating rate200 — 
July 2024(2)
Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate400 200 
(1)Floating rates are based on either SOFR or 3-month LIBOR.
(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
(3)The July 2021 interest rate swaps were amended in June 2021.
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 $253$155 million as of September 30, 2021.2022. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
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 Co-Chief Executive Officers (“Co-Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial 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 Principal Executive Officers and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 20212022 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 Principal Executive Officers 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 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, 20212022 that have materially affected, or are reasonably likely to materially affect, our internal control 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 filed with the SEC on February 19, 202118, 2022 and Note 10 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidatedin “Item 1. Financial Statements of Energy Transfer LP and Subsidiaries includedStatements” in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2021.2022.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed below were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings reasonably could result in monetary sanctions in excess of $300,000.
Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II - Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report. For additional information, please see our Quarterly Reports filed for the quarters ended March 31, 2021 and June 30, 2021.
On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filedSeptember 10, 2018, a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupturepipeline release and fire (the “Incident”) occurred on the Noble to Douglas 8-inchRevolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries.
The PA AG commenced an areainvestigation regarding the Incident, and the United States Attorney for the Western District of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediatelyPennsylvania issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.
On February 2, 2022, the PA AG issued a press release related to the Revolution pipeline, and remediatedreleased a Grand Jury Presentment and filed a criminal complaint against ETC Northeast Pipeline, LLC in Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania, with respect to nine misdemeanor charges related to various alleged violations of the surrounding environment and pipeline in cooperationClean Streams Law associated with the OCC.construction of the Revolution pipeline.
On August 5, 2022, the PA AG held a press conference to announce that the matter had been resolved through an agreement whereby ETC Northeast Pipeline, LLC entered a plea of no contest to all charges. The OCC filedresolution also included terms that the complaint alleging that SPLP failed to provide adequate cathodic protectioncompany would pay a $22,500 fine to the pipeline causingClean Water Fund at the failure. SPLPPennsylvania Department of Environmental Protection, and jointly with Sunoco Pipeline L.P. to pay certain funds to support water quality improvement projects. The plea agreement was entered into a settlement agreement with the OCC for a $500,000 penalty with an additional $500,000 suspended penalty to be voided if SPLP completes additional action items on the pipeline. SPLP had its final hearing with the OCCby court on August 18, 2021. On September 29, 2021, the OCC issued its Final Order closing the matter.
Energy Transfer received an Administrative Compliance Order from the New Mexico Environmental Department on August 28, 2020 to address the alleged noncompliance at its Jal 3 gas plant. The Compliance Order covered emission events that occurred January 1, 2017 through August 31, 2018. The Compliance Order includes an assessed civil penalty of approximately $4 million. On August 24, 2021, the New Mexico Environmental Department and Energy Transfer agreed to a Settlement Agreement and a Final Compliance Order that reduced the civil penalty to $1.3 million. Energy Transfer has completed its obligations under this Settlement Agreement and Final Compliance Order12, 2022, and the matter is now closed.
On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the PA AG, at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the PA AG served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. The Partnership has complied with the subpoena. On October 5, 2021, the PA AG held a press conference related to the Mariner East pipelines, released a Grand Jury Presentment and subsequently filed a criminal complaint against Energy Transfer in the Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania with respect to 47 misdemeanor charges related to the discharge of industrial waste and pollution and one felony charge related to the failure to report information related to the discharges.
On August 5, 2022, the PA AG held a press conference to announce that the matter had been resolved through an agreement whereby SPLP entered a plea of no contest to 14 of the misdemeanor charges, with the remaining charges being dismissed. The resolution also included terms that the company would pay a $35,000 fine to the Clean Water Fund at the Pennsylvania Department of Environmental Protection, and jointly with ETC Northeast Pipeline, LLC to resolve a parallel action by the PA AG’s office (see above), would establish a fund of $442,500 to create a Homeowner Well Water Supply Grievance Program and pay $10 million to support water quality improvement projects. The plea agreement was entered by the court on August 12, 2022, and the matter is now closed.
After an inadvertent return (“IR”) occurred on August 10, 2020 in Chester County, Pennsylvania that resulted in a discharge to Marsh Creek State Park, on September 11, 2020, the PADEP issued an Administrative Order that ordered SPLP to cease all construction at the location, grout the borehole, and perform a 1.01-mile reroute of the 20-inch pipeline in the area. SPLP filed a Notice of Appeal with the Pennsylvania Environmental Hearing Board (“EHB”) on September 25, 2020, and subsequently filed a Petition for Supersedeas on October 8, 2020. On December 16, 2020, the EHB partially granted SPLP’s Petition for Supersedeas, suspending the requirements of the Administrative Order to re-route the 20-inch pipeline and grout the HDD borehole. Following the decision, SPLP negotiated with PADEP to change the method of installation for the 20-inch pipeline

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from HDD to an open cut along an alternative route near to the original right-of-way. SPLP submitted a major permit modification to PADEP on October 7, 2021, to reflect the change in construction method and location. On December 6, 2021, a settlement was reached that resolved the EHB appeal through a Consent Order & Agreement (“COA”). The COA allowed PADEP to issue the major permit modification so that the 20-inch pipeline installation could be completed. As part of the COA, SPLP paid a $341,000 civil penalty to PADEP, SPLP paid a $4 million settlement to the Department of Conservation and Natural Resources for alleged natural resource damages to Marsh Creek State Park, SPLP agreed to complete the restoration of a wetland and stream in the area, and SPLP agreed to complete a restoration and dredging project in a portion of Marsh Creek State Park known as “Ranger Cove.” The 20-inch pipeline has now been fully installed in the area, and restoration of the wetland and streams have been completed. The restoration and dredging project at Ranger Cove commenced in April 2022 and is now complete.
For additional information required in this Item, see disclosure under the headings “Litigation and Contingencies” and “Environmental Matters” in Note 10 to our consolidated financial statements included in “Item 1. Financial Statements,”Statements”, which information is incorporated by reference into this Item.
ITEM 1A. RISK FACTORS
The following risk factor should be read in conjunction with ourThere have been no material changes from the risk factors described in "PartPart I, - Item 1A. Risk Factors"1A in the Partnership'sPartnership’s Annual Report on Form 10-KForm10-K for the year ended December 31, 20202021 filed with the SEC on February 19, 2021.
Cybersecurity attacks, data breaches and other disruptions affecting us, or our service providers, could materially and adversely affect our business, operations, reputation, and financial results.
The security and integrity of our information technology infrastructure and physical assets are critical to our business and our ability to perform day-to-day operations and deliver services. In addition, in the ordinary course of our business, we collect, process, transmit and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, as well as personally identifiable information, in our data centers and on our networks. We also engage third parties, such as service providers and vendors, who provide a broad array of software, technologies, tools, and other products, services and functions (e.g., human resources, finance, data transmission, communications, risk, compliance, among others) that enable us to conduct, monitor and/or protect our business, operations, systems and data assets.
Our information technology and infrastructure, physical assets and data, may be vulnerable to unauthorized access, computer viruses, malicious attacks and other events (e.g., distributed denial of service (“DDoS”) attacks, ransomware attacks) that are beyond our control. These events can result from malfeasance by external parties, such as hackers, or due to human error by our or our service providers’ employees and contractors (e.g., due to social engineering or phishing attacks). In addition, the
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COVID-19 pandemic has presented additional operational and cybersecurity risks to our information technology infrastructure and physical assets due to our providers’ work-from-home arrangements.
We and certain of our service providers have, from time to time, been subject to cyberattacks and security incidents. The frequency and magnitude of cyberattacks is expected to increase and attackers are becoming more sophisticated. We may be unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection, and to remove or obfuscate forensic evidence.
Breaches of our information technology infrastructure or physical assets, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations. A successful cyberattack or other security incident could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or loss could result in legal claims or proceedings, regulatory investigations and enforcement, penalties and fines, increased costs for system remediation and compliance requirements, disruption of our operations, damage to our reputation, or loss of confidence in our products and services, any or all of which could have a material adverse effect on our business and results. We may be required to invest significant additional resources to comply with evolving cybersecurity regulations and to modify and enhance our information security and controls, and to investigate and remediate any security vulnerabilities. Any losses, costs or liabilities may not be covered by, or may exceed the coverage limits of, any or all of our applicable insurance policies.18, 2022.
ITEM 6. EXHIBITS
The exhibits listed below are filed or furnished, as indicated, as part of this report:

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Exhibit NumberDescription
2.1
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
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Exhibit NumberDescription
3.10
3.11
3.12
22.1
31.1*
31.2*
31.3*
32.1**
32.2**
32.3**
101*Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements of Comprehensive Income (Loss); (iv) our Consolidated Statements of Partners’ Capital;Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements
104Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
*Filed herewith
**Furnished herewith
+Denotes a management contract or compensatory agreement

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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 LP
By:LE GP, LLC, its general partner
Date:November 4, 20213, 2022By:/s/ A. Troy Sturrock
A. Troy Sturrock
Group Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)

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