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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, ~~2021~~2022

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-32740

ENERGY TRANSFER LP

(Exact name of registrant as specified in its charter)


Delaware						30-0108820
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

New York Stock Exchange

7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETprC

New York Stock Exchange

7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETprD

New York Stock Exchange

7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETprE

New 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 filer

Accelerated filer

☐

Non-accelerated filer

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ý

At October ~~29, 2021,~~28, 2022, the registrant had ~~2,705,855,172~~3,088,475,132 Common Units outstanding.

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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:


			/d						per day





			AOCI						accumulated other comprehensive income ~~(loss)~~







			BBtu						billion British thermal units





































			Citrus						Citrus, LLC, a 50/50 joint venture which owns FGT

			Dakota Access						Dakota Access, LLC, a non-wholly-owned subsidiary of Energy Transfer



			Enable						Enable Midstream Partners, LP, a Delaware limited partnership

			Energy Transfer Canada						Energy Transfer Canada ULC, a ~~less than wholly-owned~~non-wholly-owned subsidiary of ETEnergy Transfer until its sale in August 2022

			Energy Transfer R&M						Energy Transfer (R&M), LLC (formerly Sunoco (R&M), LLC)



			ETEnergy Transfer Preferred Units						Collectively, 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 Tiger						ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of ~~ET,~~Energy Transfer, which owns the Tiger Pipeline


			ETC Sunoco						ETC Sunoco Holdings LLC (formerly Sunoco, Inc.), a wholly-owned subsidiary of Energy Transfer



			ETO						Energy Transfer Operating, L.P., formerly a non-wholly-owned subsidiary of Energy Transfer until its merger into the Partnership in April 2021



			Exchange Act						Securities Exchange Act of 1934, as amended

			Explorer						Explorer Pipeline Company






			~~ETO~~						~~Energy Transfer Operating, L.P.~~



			~~Exchange Act~~						~~Securities Exchange Act of 1934~~





			~~FEP~~						~~Fayetteville Express Pipeline LLC~~

			FERC						Federal Energy Regulatory Commission

			FGT						Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus

			GAAP						accounting principles generally accepted in the United States of America















			General Partner						LE GP, LLC, the general partner of Energy Transfer

			HFOTCO						Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ~~ET,~~Energy Transfer, which owns the Houston Terminal



			~~LE GP~~IFERC						~~LE GP, LLC, the general partner of ET~~Inside FERC’s Gas Market Report

			LIBOR						London Interbank Offered Rate















			MBbls						thousand barrels

			MEP						Midcontinent Express Pipeline LLC

			MMcf						million cubic feet

			MTBE						methyl tertiary butyl ether





			NGL						natural gas liquid, such as propane, butane and natural gasoline





			NYMEX						New York Mercantile Exchange



			OSHA						Federal Occupational Safety and Health Act

			OTC						over-the-counter

			Panhandle						Panhandle Eastern Pipe Line Company, LP, a wholly-owned subsidiary of ETEnergy Transfer































			~~Regency~~						~~Regency Energy Partners LP~~



			Rover						Rover Pipeline LLC, a non-wholly-owned subsidiary of Energy Transfer

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			SEC						Securities and Exchange Commission

			Series A Preferred Units						6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

~~Table of Contents~~

Series B Preferred Units

6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series C Preferred Units

7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series D Preferred Units

7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series E Preferred Units

7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Series F Preferred Units

6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

Series G Preferred Units

7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

Series H Preferred Units

6.500% Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

SCOOP

South Central Oklahoma Oil Province

~~Sunoco Logistics Operations~~

~~Sunoco Logistics Partners Operations L.P, a wholly-owned subsidiary of ET~~

SOFR

Secured overnight financing rate

SPLP

Sunoco Pipeline L.P., a wholly-owned subsidiary of Energy Transfer

Transwestern

Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETEnergy Transfer

Trunkline

Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle

USAC

USA Compression Partners, LP, a publicly traded partnership and consolidated subsidiary of ET

~~USAC Preferred Units~~

~~USAC Series A preferred units~~Energy Transfer

White Cliffs

White 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
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	313	$	367	Cash and cash equivalents	$	326	$	336
Accounts receivable, net	Accounts receivable, net	6,437		3,875		Accounts receivable, net	8,587		7,654
Accounts receivable from related companies	Accounts receivable from related companies	63		79		Accounts receivable from related companies	92		54
Inventories	Inventories	1,811		1,739		Inventories	2,490		2,014
Income taxes receivable	Income taxes receivable	42		35		Income taxes receivable	65		32
Derivative assets	Derivative assets	57		9		Derivative assets	19		10
Other current assets	Other current assets	326		213		Other current assets	580		437

Total current assets	Total current assets	9,049		6,317		Total current assets	12,159		10,537

Property, plant and equipment	Property, plant and equipment	95,775		94,115		Property, plant and equipment	105,040		103,991
Accumulated depreciation and depletion	Accumulated depreciation and depletion	(21,504)		(19,008)		Accumulated depreciation and depletion	(24,779)		(22,384)
		74,271		75,107
Property, plant and equipment, net						Property, plant and equipment, net	80,261		81,607

Investments in unconsolidated affiliates	Investments in unconsolidated affiliates	2,958		3,060		Investments in unconsolidated affiliates	2,869		2,947

Lease right-of-use assets, net	Lease right-of-use assets, net	829		866		Lease right-of-use assets, net	815		838

Other non-current assets, net	Other non-current assets, net	1,722		1,657		Other non-current assets, net	1,573		1,645
Intangible assets, net	Intangible assets, net	5,474		5,746		Intangible assets, net	5,505		5,856
Goodwill	Goodwill	2,395		2,391		Goodwill	2,553		2,533

Total assets	Total 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 EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	5,707	$	2,809	Accounts payable	$	7,514	$	6,834
Accounts payable to related companies	Accounts payable to related companies	—		27		Accounts payable to related companies	9		—
Derivative liabilities	Derivative liabilities	205		238		Derivative liabilities	60		203

Operating lease current liabilities	Operating lease current liabilities	46		53		Operating lease current liabilities	43		47
Accrued and other current liabilities	Accrued and other current liabilities	3,198		2,775		Accrued and other current liabilities	3,615		3,071
Current maturities of long-term debt	Current maturities of long-term debt	678		21		Current maturities of long-term debt	2		680

Total current liabilities	Total current liabilities	9,834		5,923		Total current liabilities	11,243		10,835

Long-term debt, less current maturities	Long-term debt, less current maturities	44,793		51,417		Long-term debt, less current maturities	47,413		49,022

Non-current derivative liabilities	Non-current derivative liabilities	187		237		Non-current derivative liabilities	33		193
Non-current operating lease liabilities	Non-current operating lease liabilities	799		837		Non-current operating lease liabilities	794		814
Deferred income taxes	Deferred income taxes	3,683		3,428		Deferred income taxes	3,661		3,648
Other non-current liabilities	Other non-current liabilities	1,270		1,152		Other non-current liabilities	1,530		1,323

Commitments and contingencies	Commitments and contingencies	0		0		Commitments and contingencies
Redeemable noncontrolling interests	Redeemable noncontrolling interests	783		762		Redeemable noncontrolling interests	493		783

Equity:	Equity:					Equity:
Limited Partners:	Limited Partners:					Limited Partners:
Preferred Unitholders	Preferred Unitholders	5,671		—		Preferred Unitholders	6,077		6,051
Common Unitholders	Common Unitholders	21,726		18,531		Common Unitholders	26,725		25,230
General Partner	General Partner	(5)		(8)		General Partner	(3)		(4)
Accumulated other comprehensive income	Accumulated other comprehensive income	19		6		Accumulated other comprehensive income	32		23
Total partners’ capital	Total partners’ capital	27,411		18,529		Total partners’ capital	32,831		31,300
Noncontrolling interests	Noncontrolling interests	7,938		12,859		Noncontrolling interests	7,737		8,045
Total equity	Total equity	35,349		31,388		Total equity	40,568		39,345
Total liabilities and equity	Total 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,
		2021		2020		2021		2020			2022		2021		2022		2021
REVENUES:	REVENUES:									REVENUES:
Refined product sales	Refined product sales	$	4,810	$	2,720	$	12,737	$	7,952	Refined product sales	$	6,647	$	4,810	$	20,043	$	12,737
Crude sales	Crude sales	4,021		2,298		10,920		7,170		Crude sales	5,773		4,021		17,758		10,920
NGL sales	NGL sales	4,005		1,808		10,275		4,751		NGL sales	4,823		4,005		15,828		10,275
Gathering, transportation and other fees	Gathering, transportation and other fees	2,276		2,283		6,797		6,805		Gathering, transportation and other fees	2,830		2,276		8,288		6,797
Natural gas sales	Natural gas sales	1,376		681		7,507		1,783		Natural gas sales	2,648		1,376		6,830		7,507
Other	Other	176		165		524		459		Other	218		176		628		524
Total revenues	Total revenues	16,664		9,955		48,760		28,920		Total revenues	22,939		16,664		69,375		48,760
COSTS AND EXPENSES:	COSTS AND EXPENSES:									COSTS AND EXPENSES:
Cost of products sold	Cost of products sold	13,188		6,376		35,641		18,784		Cost of products sold	18,516		13,188		56,169		35,641
Operating expenses	Operating expenses	898		773		2,585		2,422		Operating expenses	973		898		2,982		2,585
Depreciation, depletion and amortization	Depreciation, depletion and amortization	943		912		2,837		2,715		Depreciation, depletion and amortization	1,030		943		3,104		2,837
Selling, general and administrative	Selling, general and administrative	198		176		583		555		Selling, general and administrative	361		198		802		583
Impairment losses		—		1,474		11		2,803
Impairment losses and other										Impairment losses and other	86		—		386		11
Total costs and expenses	Total costs and expenses	15,227		9,711		41,657		27,279		Total costs and expenses	20,966		15,227		63,443		41,657
OPERATING INCOME	OPERATING INCOME	1,437		244		7,103		1,641		OPERATING INCOME	1,973		1,437		5,932		7,103
OTHER INCOME (EXPENSE):	OTHER INCOME (EXPENSE):									OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	Interest 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 affiliates		71		(32)		191		46
Impairment of investment in an unconsolidated affiliate		—		(129)		—		(129)
Equity in earnings of unconsolidated affiliates										Equity in earnings of unconsolidated affiliates	68		71		186		191

Losses on extinguishments of debt	Losses on extinguishments of debt	—		—		(8)		(62)		Losses on extinguishments of debt	—		—		—		(8)
Gains (losses) on interest rate derivatives		1		55		72		(277)
Gains on interest rate derivatives										Gains on interest rate derivatives	60		1		303		72
Other, net	Other, net	33		71		45		6		Other, net	(120)		33		(117)		45
INCOME (LOSS) BEFORE INCOME TAX EXPENSE		984		(360)		5,690		(525)
INCOME BEFORE INCOME TAX EXPENSE										INCOME BEFORE INCOME TAX EXPENSE	1,404		984		4,590		5,690
Income tax expense	Income tax expense	77		41		234		168		Income tax expense	82		77		159		234
NET INCOME (LOSS)		907		(401)		5,456		(693)
NET INCOME										NET INCOME	1,322		907		4,431		5,456
Less: Net income attributable to noncontrolling interests	Less: Net income attributable to noncontrolling interests	260		242		870		427		Less: Net income attributable to noncontrolling interests	304		260		793		870
Less: Net income attributable to redeemable noncontrolling interests	Less: Net income attributable to redeemable noncontrolling interests	12		12		37		37		Less: Net income attributable to redeemable noncontrolling interests	12		12		37		37
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS		635		(655)		4,549		(1,157)
General Partner’s interest in net income (loss)		1		—		5		(1)
NET INCOME ATTRIBUTABLE TO PARTNERS										NET INCOME ATTRIBUTABLE TO PARTNERS	1,006		635		3,601		4,549
General Partner’s interest in net income										General Partner’s interest in net income	1		1		3		5
Preferred Unitholders’ interest in net income	Preferred Unitholders’ interest in net income	99		—		185		—		Preferred Unitholders’ interest in net income	106		99		317		185
Limited Partners’ interest in net income (loss)		$	535	$	(655)	$	4,359	$	(1,156)
Common Unitholders’ interest in net income										Common 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:
Basic	Basic	$	0.20	$	(0.24)	$	1.61	$	(0.43)	Basic	$	0.29	$	0.20	$	1.06	$	1.61
Diluted	Diluted	$	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,
		2021		2020		2021		2020			2022		2021		2022		2021
Net income (loss)		$	907	$	(401)	$	5,456	$	(693)
Net income										Net 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 securities	Change in value of available-for-sale securities	2		3		5		3		Change in value of available-for-sale securities	(4)		2		(13)		5
Actuarial gain related to pension and other postretirement benefit plans	Actuarial gain related to pension and other postretirement benefit plans	1		4		6		15		Actuarial gain related to pension and other postretirement benefit plans	—		1		7		6
Foreign currency translation adjustments	Foreign currency translation adjustments	(21)		18		3		(16)		Foreign currency translation adjustments	13		(21)		(6)		3
Change in other comprehensive income (loss) from unconsolidated affiliates		1		1		1		(15)
Change in other comprehensive income from unconsolidated affiliates										Change in other comprehensive income from unconsolidated affiliates	6		1		24		1
		(17)		26		15		(13)			15		(17)		12		15
Comprehensive income (loss)		890		(375)		5,471		(706)
Comprehensive income										Comprehensive income	1,337		890		4,443		5,471
Less: Comprehensive income attributable to noncontrolling interests	Less: Comprehensive income attributable to noncontrolling interests	250		251		872		407		Less: Comprehensive income attributable to noncontrolling interests	307		250		787		872
Less: Comprehensive income attributable to redeemable noncontrolling interests	Less: Comprehensive income attributable to redeemable noncontrolling interests	12		12		37		37		Less: Comprehensive income attributable to redeemable noncontrolling interests	12		12		37		37
Comprehensive income (loss) attributable to partners		$	628	$	(638)	$	4,562	$	(1,150)
Comprehensive income attributable to partners										Comprehensive 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 Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total			Common Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total
Balance, December 31, 2020		$	18,531	$	—	$	(8)	$	6	$	12,859	$	31,388
Balance, December 31, 2021														Balance, December 31, 2021	$	25,230	$	6,051	$	(4)	$	23	$	8,045	$	39,345
Distributions to partners	Distributions to partners	(406)		—		—		—		—		(406)		Distributions to partners	(528)		(80)		—		—		—		(608)
Distributions to noncontrolling interests	Distributions to noncontrolling interests	—		—		—		—		(406)		(406)		Distributions to noncontrolling interests	—		—		—		—		(307)		(307)

Capital contributions from noncontrolling interests	Capital contributions from noncontrolling interests	—		—		—		—		20		20		Capital contributions from noncontrolling interests	—		—		—		—		373		373
Other comprehensive income, net of tax	Other comprehensive income, net of tax	—		—		—		2		6		8		Other comprehensive income, net of tax	—		—		—		20		5		25
Other, net	Other, net	18		—		—		—		3		21		Other, net	17		—		—		—		10		27
Net income, excluding amounts attributable to redeemable noncontrolling interests	Net income, excluding amounts attributable to redeemable noncontrolling interests	3,285		—		3		—		341		3,629		Net income, excluding amounts attributable to redeemable noncontrolling interests	1,162		106		1		—		205		1,474
Balance, March 31, 2021		21,428		—		(5)		8		12,823		34,254
Preferred units converted in Rollup Mergers		—		4,768		—		—		(4,768)		—
Balance, March 31, 2022														Balance, March 31, 2022	25,881		6,077		(3)		43		8,331		40,329

Distributions to partners	Distributions to partners	(403)		(88)		(1)		—		—		(492)		Distributions to partners	(603)		(131)		(1)		—		—		(735)
Distributions to noncontrolling interests	Distributions 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		6		24
Other, net		15		(1)		—		—		2		16
Net income, excluding amounts attributable to redeemable noncontrolling interests		539		86		1		—		269		895
Balance, June 30, 2021		21,579		5,654		(5)		26		8,021		35,275
Distributions to partners		(404)		(80)		(1)		—		—		(485)
Distributions to noncontrolling interests		0		—		—		—		(389)		(389)
Capital contributions from noncontrolling interests	Capital contributions from noncontrolling interests	—		—		—		—		51		51		Capital contributions from noncontrolling interests	—		—		—		—		24		24

Other comprehensive loss, net of tax	Other comprehensive loss, net of tax	—		—		—		(7)		(10)		(17)		Other comprehensive loss, net of tax	—		—		—		(14)		(14)		(28)
Other, net	Other, net	16		(2)		—		—		5		19		Other, net	9		—		—		—		2		11
Net income, excluding amounts attributable to redeemable noncontrolling interests	Net income, excluding amounts attributable to redeemable noncontrolling interests	535		99		1		—		260		895		Net income, excluding amounts attributable to redeemable noncontrolling interests	1,220		105		1		—		284		1,610
Balance, September 30, 2021		$	21,726	$	5,671	$	(5)	$	19	$	7,938	$	35,349
Balance, June 30, 2022														Balance, June 30, 2022	26,507		6,051		(3)		29		8,181		40,765
Distributions to partners														Distributions to partners	(694)		(80)		(1)		—		—		(775)
Distributions to noncontrolling interests														Distributions to noncontrolling interests			—		—		—		(424)		(424)
Capital contributions from noncontrolling interests														Capital contributions from noncontrolling interests	—		—		—		—		7		7

Energy Transfer Canada sale														Energy Transfer Canada sale	—		—		—		(9)		(337)		(346)
Other comprehensive income, net of tax														Other comprehensive income, net of tax	—		—		—		12		3		15
Other, net														Other, net	13		—		—		—		3		16
Net income, excluding amounts attributable to redeemable noncontrolling interests														Net income, excluding amounts attributable to redeemable noncontrolling interests	899		106		1		—		304		1,310
Balance, September 30, 2022														Balance, 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 Unitholders		General Partner		AOCI		Noncontrolling Interests		Total			Common Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total
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, net		22		—		—		(7)		15
Net loss, excluding amounts attributable to redeemable noncontrolling interests		(854)		(1)		—		(121)		(976)
Balance, March 31, 2020		19,512		(6)		(59)		13,083		32,530
Distributions to partners		9		(1)		—		—		8
Distributions to noncontrolling interests		—		—		—		(408)		(408)

Capital contributions from noncontrolling interests		—		—		—		83		83
Other comprehensive income, net of tax		—		—		38		9		47
Other, net		(31)		—		—		4		(27)
Net income, excluding amounts attributable to redeemable noncontrolling interests		353		—		—		306		659
Balance, June 30, 2020		19,843		(7)		(21)		13,077		32,892
Balance, December 31, 2020												Balance, December 31, 2020	$	18,531	$	—	$	(8)	$	6	$	12,859	$	31,388
Distributions to partners	Distributions to partners	(812)		(1)		—		—		(813)		Distributions to partners	(406)		—		—		—		—		(406)
Distributions to noncontrolling interests	Distributions to noncontrolling interests	—		—		—		(430)		(430)		Distributions to noncontrolling interests	—		—		—		—		(406)		(406)

Capital contributions from noncontrolling interests	Capital contributions from noncontrolling interests	—		—		—		25		25		Capital contributions from noncontrolling interests	—		—		—		—		20		20
Other comprehensive income, net of tax	Other comprehensive income, net of tax	—		—		17		9		26		Other comprehensive income, net of tax	—		—		—		2		6		8
Other, net	Other, net	47		—		—		(43)		4		Other, net	18		—		—		—		3		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 interests												Net income, excluding amounts attributable to redeemable noncontrolling interests	3,285		—		3		—		341		3,629
Balance, March 31, 2021												Balance, March 31, 2021	21,428		—		(5)		8		12,823		34,254
Preferred units converted in Rollup Mergers												Preferred units converted in Rollup Mergers	—		4,768		—		—		(4,768)		—
Distributions to partners												Distributions to partners	(403)		(88)		(1)		—		—		(492)
Distributions to noncontrolling interests												Distributions to noncontrolling interests	—		—		—		—		(354)		(354)
Units issued												Units issued	—		889		—		—		—		889
Capital contributions from noncontrolling interests												Capital contributions from noncontrolling interests	—		—		—		—		43		43

Other comprehensive income, net of tax												Other comprehensive income, net of tax	—		—		—		18		6		24
Other, net												Other, net	15		(1)		—		—		2		16
Net income, excluding amounts attributable to redeemable noncontrolling interests												Net income, excluding amounts attributable to redeemable noncontrolling interests	539		86		1		—		269		895
Balance, June 30, 2021												Balance, June 30, 2021	21,579		5,654		(5)		26		8,021		35,275
Distributions to partners												Distributions to partners	(404)		(80)		(1)		—		—		(485)
Distributions to noncontrolling interests												Distributions to noncontrolling interests	—		—		—		—		(389)		(389)
Capital contributions from noncontrolling interests												Capital contributions from noncontrolling interests	—		—		—		—		51		51

Other comprehensive loss, net of tax												Other comprehensive loss, net of tax	—		—		—		(7)		(10)		(17)
Other, net												Other, net	16		(2)		—		—		5		19
Net income, excluding amounts attributable to redeemable noncontrolling interests												Net income, excluding amounts attributable to redeemable noncontrolling interests	535		99		1		—		260		895
Balance, September 30, 2021												Balance, 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,
		2021		2020			2022		2021
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 income						Net 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 amortization	Depreciation, depletion and amortization	2,837		2,715		Depreciation, depletion and amortization	3,104		2,837
Deferred income taxes	Deferred income taxes	199		159		Deferred income taxes	158		199
Inventory valuation adjustments	Inventory valuation adjustments	(168)		126		Inventory valuation adjustments	(81)		(168)
Non-cash compensation expense	Non-cash compensation expense	81		93		Non-cash compensation expense	88		81
Impairment losses	Impairment losses	11		2,803		Impairment losses	386		11
Impairment of investment in an unconsolidated affiliate		—		129

Losses on extinguishments of debt	Losses on extinguishments of debt	8		62		Losses on extinguishments of debt	—		8
Distributions on unvested awards	Distributions on unvested awards	(19)		(33)		Distributions on unvested awards	(37)		(19)
Equity in earnings of unconsolidated affiliates	Equity in earnings of unconsolidated affiliates	(191)		(46)		Equity in earnings of unconsolidated affiliates	(186)		(191)
Distributions from unconsolidated affiliates	Distributions from unconsolidated affiliates	226		176		Distributions from unconsolidated affiliates	182		226
Other non-cash	Other non-cash	13		(130)		Other non-cash	(120)		13
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 divestitures						Net change in operating assets and liabilities, net of effects of acquisitions and divestitures	(212)		970
Net cash provided by operating activities	Net cash provided by operating activities	9,423		5,455		Net cash provided by operating activities	7,713		9,423
INVESTING ACTIVITIES:	INVESTING ACTIVITIES:					INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received						Cash paid for acquisitions, net of cash received	(1,062)		—

Capital expenditures, excluding allowance for equity funds used during construction	Capital 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 costs	Contributions in aid of construction costs	29		61		Contributions in aid of construction costs	50		29
Contributions to unconsolidated affiliates	Contributions to unconsolidated affiliates	(4)		(37)		Contributions to unconsolidated affiliates	—		(4)
Distributions from unconsolidated affiliates in excess of cumulative earnings	Distributions from unconsolidated affiliates in excess of cumulative earnings	76		144		Distributions from unconsolidated affiliates in excess of cumulative earnings	66		76
Proceeds from sale of Energy Transfer Canada interest						Proceeds from sale of Energy Transfer Canada interest	302		—
Proceeds from sales of other assets	Proceeds from sales of other assets	38		10		Proceeds from sales of other assets	60		38
Other		—		(9)

Net cash used in investing activities	Net 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 borrowings	Proceeds from borrowings	11,839		20,651		Proceeds from borrowings	19,400		11,839
Repayments of debt	Repayments of debt	(17,836)		(20,293)		Repayments of debt	(21,110)		(17,836)
Preferred Units issued for cash		889		—
Subsidiary units issued for cash		—		1,580
Preferred units issued for cash						Preferred units issued for cash	—		889

Capital contributions from noncontrolling interests	Capital contributions from noncontrolling interests	114		203		Capital contributions from noncontrolling interests	404		114
Distributions to partners	Distributions to partners	(1,383)		(2,397)		Distributions to partners	(2,118)		(1,383)
Distributions to noncontrolling interests	Distributions 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 interests						Distributions to redeemable noncontrolling interests	(37)		(37)
Debt issuance costs	Debt issuance costs	(3)		(53)		Debt issuance costs	(9)		(3)
Other, net	Other, net	(4)		18		Other, net	1		(4)
Net cash used in financing activities	Net cash used in financing activities	(7,570)		(1,610)		Net cash used in financing activities	(4,646)		(7,570)
Decrease in cash and cash equivalents	Decrease in cash and cash equivalents	(54)		(16)		Decrease in cash and cash equivalents	(10)		(54)
Cash and cash equivalents, beginning of period	Cash and cash equivalents, beginning of period	367		291		Cash and cash equivalents, beginning of period	336		367
Cash and cash equivalents, end of period	Cash 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. Ownership~~and 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 ~~RELATED~~DIVESTITURE TRANSACTIONS

~~Pending Enable~~Woodford 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 agreement~~completed the previously announced sale of its 51% interest in Energy Transfer Canada. The sale resulted in cash proceeds to ~~acquire Enable. Under~~Energy Transfer of C$390 million (US$302 million).

Energy Transfer Canada’s assets and operations were included in the ~~terms~~Partnership’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 ~~merger~~share purchase agreement ~~Enable’s common unitholders will receive 0.8595~~in 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 Preferred~~which $164 million was allocated to noncontrolling interests and $136 million was

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~~Unit, and ET will make a $10~~reflected in net income attributable to partners. Upon the completion of the sale in August 2022, the Partnership recorded an $85 million ~~cash payment~~loss 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 May~~approximately $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 requests~~preliminary 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 compliance~~year ended December 31, 2021, filed with the ~~Second Request, unless that period is extended voluntarily or terminated sooner by~~SEC on February 18, 2022.

Sunoco LP Acquisition

On April 1, 2022, Sunoco LP completed the ~~FTC. We continue~~acquisition of a transmix processing and terminal facility in Huntington, Indiana for $252 million, net of cash acquired, of which $98 million was allocated to ~~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 committed~~equipment 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, ~~2021~~2022 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,
		2021		2020			2022		2021
Accounts receivable	Accounts receivable	$	(2,562)	$	1,307	Accounts receivable	$	(999)	$	(2,562)
Accounts receivable from related companies	Accounts receivable from related companies	16		(258)		Accounts receivable from related companies	17		16
Inventories	Inventories	96		(298)		Inventories	(287)		96
Other current assets	Other current assets	(127)		108		Other current assets	(176)		(127)
Other non-current assets, net	Other non-current assets, net	(57)		(26)		Other non-current assets, net	106		(57)
Accounts payable	Accounts payable	2,917		(1,354)		Accounts payable	599		2,917
Accounts payable to related companies	Accounts payable to related companies	(31)		370		Accounts payable to related companies	1		(31)
Accrued and other current liabilities	Accrued and other current liabilities	711		127		Accrued and other current liabilities	585		711
Other non-current liabilities	Other non-current liabilities	138		(5)		Other non-current liabilities	254		138
Derivative assets and liabilities, net	Derivative 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 divestitures						Net 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,
		2021		2020			2022		2021
NON-CASH INVESTING AND FINANCING ACTIVITIES:

Accrued capital expenditures	Accrued capital expenditures	$	385	$	684	Accrued capital expenditures	$	454	$	385

Lease assets obtained in exchange for new lease liabilities	Lease assets obtained in exchange for new lease liabilities	10		130		Lease assets obtained in exchange for new lease liabilities	37		10
Distribution reinvestment	Distribution reinvestment	24		72		Distribution reinvestment	42		24

4.INVENTORIES

Inventories ~~consist principally~~consisted 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:

~~Table of Contents~~


	September 30, 2022		December 31, 2021
Natural gas, NGLs and refined products	$	1,910	$	1,259
Crude oil	166		328
Spare parts and other	414		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, ~~2021~~2022 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, and~~respectively. 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, ~~2021~~2022 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 oil 160 287
Spare parts and other 413 439
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 for~~LP’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 statements~~included 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 ~~our~~a clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. ~~We consider the~~The 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, ~~2021~~2022 and December 31, ~~2020~~2021 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 Total		Level 1		Level 2			Fair Value Total		Level 1		Level 2
Assets:	Assets:							Assets:

Commodity derivatives:	Commodity derivatives:							Commodity derivatives:

Natural Gas:	Natural Gas:							Natural Gas:
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	$	14	$	14	$	—	Basis Swaps IFERC/NYMEX	$	23	$	23	$	—
Swing Swaps IFERC	Swing Swaps IFERC	11		11		—		Swing Swaps IFERC	27		27		—
Fixed Swaps/Futures	Fixed Swaps/Futures	4		4		—		Fixed Swaps/Futures	50		50		—

Forward Physical Contracts	Forward Physical Contracts	4		—		4		Forward Physical Contracts	8		—		8
Power:	Power:							Power:
Forwards	Forwards	36		—		36		Forwards	63		—		63
Futures	Futures	4		4		—		Futures	6		6		—

Options – Calls		1		1		—

NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	384		384		—		NGLs – Forwards/Swaps	669		669		—
Refined Products – Futures	Refined Products – Futures	7		7		—		Refined Products – Futures	11		11		—
Crude – Forwards/Swaps	Crude – Forwards/Swaps	569		569		—		Crude – Forwards/Swaps	26		26		—

Total commodity derivatives	Total commodity derivatives	1,034		994		40		Total commodity derivatives	883		812		71
Other non-current assets	Other non-current assets	37		24		13		Other non-current assets	31		20		11
Total assets	Total assets	$	1,071	$	1,018	$	53	Total assets	$	914	$	832	$	82
Liabilities:	Liabilities:							Liabilities:
Interest rate derivatives	Interest rate derivatives	$	(376)	$	—	$	(376)	Interest rate derivatives	$	(84)	$	—	$	(84)
Commodity derivatives:	Commodity derivatives:							Commodity derivatives:
Natural Gas:	Natural Gas:							Natural Gas:
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(5)		(5)		—		Basis Swaps IFERC/NYMEX	(11)		(11)		—
Swing Swaps IFERC	Swing Swaps IFERC	(7)		(7)		—		Swing Swaps IFERC	(2)		(2)		—
Fixed Swaps/Futures	Fixed Swaps/Futures	(78)		(78)		—		Fixed Swaps/Futures	(63)		(63)		—

Forward Physical Contracts	Forward Physical Contracts	(1)		—		(1)		Forward Physical Contracts	(2)		—		(2)
Power:	Power:							Power:
Forwards	Forwards	(21)		—		(21)		Forwards	(57)		—		(57)
Futures	Futures	(11)		(11)		—		Futures	(9)		(9)		—
Options – Calls	Options – Calls	(2)		(2)		—		Options – Calls	(1)		(1)		—

NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	(364)		(364)		—		NGLs – Forwards/Swaps	(493)		(493)		—
Refined Products – Futures	Refined Products – Futures	(10)		(10)		—		Refined Products – Futures	(8)		(8)		—
Crude – Forwards/Swaps	Crude – Forwards/Swaps	(582)		(582)		—		Crude – Forwards/Swaps	(14)		(14)		—
Total commodity derivatives	Total commodity derivatives	(1,081)		(1,059)		(22)		Total commodity derivatives	(660)		(601)		(59)
Total liabilities	Total liabilities	$	(1,457)	$	(1,059)	$	(398)	Total liabilities	$	(744)	$	(601)	$	(143)

~~Table~~Ta b le of Contents


				Fair Value Measurements at December 31, 2020					Fair Value Measurements at December 31, 2021
		Fair Value Total		Level 1		Level 2			Fair Value Total		Level 1		Level 2
Assets:	Assets:							Assets:

Commodity derivatives:	Commodity derivatives:							Commodity derivatives:

Natural Gas:	Natural Gas:							Natural Gas:
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	$	12	$	12	$	—	Basis Swaps IFERC/NYMEX	$	7	$	7	$	—
Swing Swaps IFERC	Swing Swaps IFERC	1		—		1		Swing Swaps IFERC	38		38		—
Fixed Swaps/Futures	Fixed Swaps/Futures	13		13		—		Fixed Swaps/Futures	26		26		—

Forward Physical Contracts	Forward Physical Contracts	5		—		5		Forward Physical Contracts	7		—		7
Power:	Power:							Power:
Forwards	Forwards	4		—		4		Forwards	17		—		17
Futures	Futures	2		2		—		Futures	6		6		—

Options – Calls		1		1		—

NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	127		127		—		NGLs – Forwards/Swaps	152		152		—
Refined Products – Futures	Refined Products – Futures	3		3		—		Refined Products – Futures	3		3		—

Crude – Forwards/Swaps								Crude – Forwards/Swaps	16		16		—

Total commodity derivatives	Total commodity derivatives	168		158		10		Total commodity derivatives	272		248		24
Other non-current assets	Other non-current assets	34		22		12		Other non-current assets	39		26		13
Total assets	Total assets	$	202	$	180	$	22	Total assets	$	311	$	274	$	37
Liabilities:	Liabilities:							Liabilities:
Interest rate derivatives	Interest rate derivatives	$	(448)	$	—	$	(448)	Interest rate derivatives	$	(387)	$	—	$	(387)
Commodity derivatives:	Commodity derivatives:							Commodity derivatives:
Natural Gas:	Natural Gas:							Natural Gas:
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(11)		(11)		—		Basis Swaps IFERC/NYMEX	(10)		(10)		—
Swing Swaps IFERC	Swing Swaps IFERC	(3)		—		(3)		Swing Swaps IFERC	(6)		(6)		—
Fixed Swaps/Futures	Fixed Swaps/Futures	(13)		(13)		—		Fixed Swaps/Futures	(9)		(9)		—

Forward Physical Contracts	Forward Physical Contracts	(1)		—		(1)		Forward Physical Contracts	(6)		—		(6)
Power:	Power:							Power:

Forwards								Forwards	(15)		—		(15)
Futures	Futures	(3)		(3)		—		Futures	(4)		(4)		—

NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	(227)		(227)		—		NGLs – Forwards/Swaps	(140)		(140)		—
Refined Products – Futures	Refined Products – Futures	(11)		(11)		—		Refined Products – Futures	(18)		(18)		—

Crude – Forwards/Swaps								Crude – Forwards/Swaps	(3)		(3)		—

Total commodity derivatives	Total commodity derivatives	(269)		(265)		(4)		Total commodity derivatives	(211)		(190)		(21)
Total liabilities	Total 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, ~~2021~~2022 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.

~~Table~~Ta b le of Contents

6.NET INCOME ~~(LOSS)~~ PER ~~LIMITED PARTNER~~COMMON 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,
2021 2020 2021 2020
Net income (loss) $ 907 $ (401) $ 5,456 $ (693)
Less: Net income attributable to noncontrolling interests 260 242 870 427
Less: Net income attributable to redeemable noncontrolling interests 12 12 37 37
Net income (loss), net of noncontrolling interests 635 (655) 4,549 (1,157)
Less: General Partner’s interest in income (loss) 1 — 5 (1)
Less: Preferred Unitholders’ interest in income 99 — 185 —
Income (loss) available to Limited Partners $ 535 $ (655) $ 4,359 $ (1,156)
Basic Income (Loss) per Limited Partner Unit:
Weighted average limited partner units 2,705.2 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)
1 — 2 —
Diluted income (loss) available to Limited Partners $ 534 $ (655) $ 4,357 $ (1,156)
Weighted average limited partner units 2,705.2 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 awards 2,720.6 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,
	2022		2021		2022		2021
Net income	$	1,322	$	907	$	4,431	$	5,456
Less: Net income attributable to noncontrolling interests	304		260		793		870
Less: Net income attributable to redeemable noncontrolling interests	12		12		37		37
Net income, net of noncontrolling interests	1,006		635		3,601		4,549
Less: General Partner’s interest in net income	1		1		3		5
Less: Preferred Unitholders’ interest in net income	106		99		317		185
Common Unitholders’ interest in net income	$	899	$	535	$	3,281	$	4,359
Basic Income per Common Unit:
Weighted average common units	3,087.6		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)	—		1		2		2
Diluted income attributable to Common Unitholders	$	899	$	534	$	3,279	$	4,357
Weighted average common units	3,087.6		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 awards	3,108.6		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 with~~February 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, ETO~~Partnership redeemed ~~its $600~~$300 million aggregate principal amount of ~~4.40% senior notes~~its 4.65% Senior Notes due February 2022 using proceeds from its Five-Year Credit Facility (defined below).

In April ~~1, 2021 and its $800~~2022, Dakota Access redeemed $650 million aggregate principal amount of ~~4.65% senior notes~~its 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.

~~During~~In August 2022, the ~~third quarter of 2021, ET issued~~Partnership 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 ~~$900~~fully redeemed $700 million aggregate principal amount of ~~5.875% senior notes~~its 5.00% Senior Notes due ~~March 1, 2022. The Partnership expects to redeem both series of senior notes during the fourth quarter of 2021, utilizing~~October 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.

~~Table of Contents~~

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 its~~The 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, ~~2021~~2022 was ~~0.43%~~4.29%.

~~364-Day Facility~~

~~As a result~~17

Ta b le 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, the~~2022, Sunoco ~~LP Credit Facility~~LP’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, ~~2021~~2022 was ~~$1.24 billion.~~$789 million. The weighted average interest rate on the total amount outstanding as of September 30, ~~2021~~2022 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, USAC~~2022, 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, ~~2021~~2022 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.

~~Table of Contents~~

8.REDEEMABLE NONCONTROLLING INTERESTS

Certain redeemable noncontrolling interests in the Partnership’s subsidiaries ~~are~~were reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of September 30, ~~2021~~2022 included a balance of $477 million related to the USAC ~~Preferred Units described below~~Series 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 included~~Partnership 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 300,000~~preferred 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 at~~were 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 change~~Changes in ETEnergy Transfer common units during the nine months ended September 30, ~~2021 was~~2022 were as follows:


			Number of Units
Number of common units at December 31, ~~2020~~2021			~~2,702.4~~3,082.5
Common units issued ~~in connection with~~under the distribution reinvestment plan			~~2.7~~3.8

Common units vested under equity incentive plans and other			~~0.7~~2.1
Number of common units at September 30, ~~2021~~2022			~~2,705.8~~3,088.4

ETEnergy Transfer Repurchase Program

During the nine months ended September 30, ~~2021, ET~~2022, Energy Transfer did not repurchase any ETof its common units under its current buyback program. As of September 30, ~~2021, $911~~2022, $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.

~~Table~~Ta b le of Contents

Cash Distributions on ETEnergy Transfer Common Units

Distributions declared and/or paid with respect to ETEnergy Transfer common units subsequent to December 31, ~~2020~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2020~~2021

February 8, ~~2021~~2022

February ~~19, 2021~~18, 2022

~~0.1525~~0.1750

March 31, ~~2021~~2022

May ~~11, 2021~~9, 2022

May 19, ~~2021~~2022

~~0.1525~~0.2000

June 30, ~~2021~~2022

August ~~6, 2021~~8, 2022

August 19, ~~2021~~2022

~~0.1525~~0.2300

September 30, ~~2021~~2022

November ~~5, 2021~~4, 2022

November ~~19, 2021~~21, 2022

~~0.1525~~0.2650

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 ET~~Energy Transfer Preferred Units

In connection with the ~~Rollup Mergers~~merger of Energy Transfer, ETO, and certain of ETO’s subsidiaries (the “Rollup Mergers”) on April 1, 2021, as ~~discussed~~described 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’s~~Energy 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, ~~1,100,000~~1,484,780 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 A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
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 income	15		9		8		9		15		8		27		15		106
Balance, March 31, 2022	943		547		440		434		786		504		1,515		908		6,077


Distributions to partners	—		—		(8)		(9)		(15)		(16)		(53)		(30)		(131)

Net income	15		9		8		9		15		8		26		15		105
Balance, June 30, 2022	958		556		440		434		786		496		1,488		893		6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)

Net income	15		9		8		9		15		8		27		15		106
Balance, September 30, 2022	$	943	$	547	$	440	$	434	$	786	$	504	$	1,515	$	908	$	6,077


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, March 31, 2021	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Preferred units conversion	943		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 income	15		9		8		9		15		8		20		2		86
Balance, June 30, 2021	958		556		440		434		786		495		1,095		890		5,654
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)
Other, net	—		—		—		—		—		—		—		(2)		(2)
Net income	15		9		8		9		15		8		20		15		99
Balance, September 30, 2021	$	943	$	547	$	440	$	434	$	786	$	503	$	1,115	$	903	$	5,671

Ta b le of Contents

Cash Distributions on ETEnergy Transfer Preferred Units

Distributions declared on the ETEnergy Transfer Preferred Units were as follows:

~~Table of Contents~~

Period Ended Record Date Payment Date
Series A (1)
Series B (1)
Series C Series D Series E
Series F (1)
Series G (1)
Series H (1)
March 31, 2021 May 3, 2021 May 17, 2021 $ — $ — $ 0.4609 $ 0.4766 $ 0.4750 $ 33.75 $ 35.625 $ —
June 30, 2021 August 2, 2021 August 16, 2021 31.25 33.125 0.4609 0.4766 0.4750 — — —
September 30, 2021 November 1, 2021 November 15, 2021 — — 0.4609 0.4766 0.4750 33.75 35.625 27.08 (2)


Period Ended	Record Date	Payment Date	Series A (1)		Series B (1)		Series C		Series D		Series E		Series F (1)		Series G (1)		Series H (1)
December 31, 2021	February 1, 2022	February 15, 2022	$	31.250	$	33.125	$	0.4609	$	0.4766	$	0.475	$	—	$	—	$	—
March 31, 2022	May 2, 2022	May 16, 2022	—		—		0.4609		0.4766		0.475		33.750		35.625		32.500
June 30, 2022	August 1, 2022	August 15, 2022	31.250		33.125		0.4609		0.4766		0.475		—		—		—
September 30, 2022	November 1, 2022	November 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 ET~~For 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. Distributions~~Rollup 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 Interests~~year 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, ~~2020~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2020~~2021

February 8, ~~2021~~2022

February ~~19, 2021~~18, 2022

0.8255

March 31, ~~2021~~2022

May ~~11, 2021~~9, 2022

May 19, ~~2021~~2022

0.8255

June 30, ~~2021~~2022

August ~~6, 2021~~8, 2022

August 19, ~~2021~~2022

0.8255

September 30, ~~2021~~2022

November ~~5, 2021~~4, 2022

November ~~19, 2021~~18, 2022

0.8255

USAC Cash Distributions

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, ~~2020~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2020~~2021

January ~~25, 2021~~24, 2022

February ~~5, 2021~~4, 2022

0.525

March 31, ~~2021~~2022

April ~~26, 2021~~25, 2022

May ~~7, 2021~~6, 2022

0.525

June 30, ~~2021~~2022

July ~~26, 2021~~25, 2022

August ~~6, 2021~~5, 2022

0.525

September 30, ~~2021~~2022

October ~~25, 2021~~24, 2022

November ~~5, 2021~~4, 2022

0.525

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 securities	Available-for-sale securities	$	23	$	18	Available-for-sale securities	$	6	$	19
Foreign currency translation adjustment	Foreign currency translation adjustment	12		7		Foreign currency translation adjustment	1		13
Actuarial loss related to pensions and other postretirement benefits		(1)		(7)
Actuarial gains related to pensions and other postretirement benefits						Actuarial gains related to pensions and other postretirement benefits	12		5
Investments in unconsolidated affiliates, net	Investments in unconsolidated affiliates, net	(13)		(14)		Investments in unconsolidated affiliates, net	13		(11)

Total AOCI, net of tax	Total AOCI, net of tax	21		4		Total AOCI, net of tax	32		26
Amounts attributable to noncontrolling interest	Amounts attributable to noncontrolling interest	(2)		2		Amounts attributable to noncontrolling interest	—		(3)
Total AOCI included in partners’ capital, net of tax	Total AOCI included in partners’ capital, net of tax	$	19	$	6	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 ~~Order~~commencement 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, process~~Energy Transfer purchases, processes and ~~sell~~sells 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 believe~~Energy 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,
2021 2020 2021 2020
ROW expense $ 18 $ 13 $ 33 $ 32


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
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. ~~Natural~~Due to the flammable and combustible nature of natural gas and crude oil, ~~are flammable and combustible. Serious~~the potential exists for personal injury ~~and significant~~and/or property damage ~~can arise~~to 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 party~~parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

As of September 30, ~~2021~~2022 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 ~~contingencies~~contingent 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 that~~Energy Transfer anticipates the draft EIS will be ~~complete~~completed and published by the ~~end~~USACE in the Spring of 2023, subject to additional delays by the USACE. The release of the draft EIS was paused following the SRST’s withdrawal as a cooperating agency on January 20, 2022. 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’s~~Mont 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 ~~States~~State 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

Ta b le 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 Williams~~The 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-Williams~~Energy 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 ~~series~~Series 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. ET~~final judgment against the Energy Transfer Defendants ~~cannot predict the outcome of the Williams Litigation nor can the ET Defendants predict~~in the amount of ~~time and expense that will be required to resolve~~approximately $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 concluded~~On March 17, 2022, the Ohio Supreme Court reversed in part and ~~oral argument was held~~remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.

On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one 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 ~~scope~~resolution also included terms that the company would pay a $22,500 fine to the Clean Water Fund at the Pennsylvania Department of ~~these investigations~~Environmental 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 been~~was 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 he~~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 ~~running for Governor of Pennsylvania.~~now closed.

Shareholder Litigation Regarding ~~Pennsylvania~~ Pipeline Construction

~~Four~~Various purported unitholders of ETEnergy Transfer have filed derivative actions against various past and current members of ~~ET’s~~Energy 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’s~~Energy 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’s~~Energy Transfer’s corporate governance structure. See Bettiol v. LE GP,, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren,, Case No. 2:20-cv-00364-GAM (E.D. Pa.); ~~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’s~~Energy Transfer’s directors, Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP,, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants 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 ~~SPMT~~Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ~~SPMT~~ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.

On August 27, 2020, ~~SPMT~~ETMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. The matter ~~has now been~~was fully briefed, and oral argument ~~has been~~was set for November 15, 2021. ~~SPMT~~However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition

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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 ~~SPMT~~ETMT predict the amount of time and expense that will be required to resolve the ~~appeal, but intends to vigorously appeal~~appeal. A Petition for Writ of Certiorari was filed with the ~~entirety~~United 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
Current	Current	$	44	$	44	Current	$	46	$	46
Non-current	Non-current	253		262		Non-current	231		247
Total environmental liabilities	Total 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, ~~2021~~2022 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 Transportation~~DOT 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 term~~long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

The following table summarizes the consolidated activity of our contract liabilities:


	Contract Liabilities
Balance, December 31, 2021	$	459
Additions	815
Revenue recognized	(688)
Other	(13)
Balance, September 30, 2022	$	573

Balance, December 31, 2020	$	~~308~~309
Additions	611
Revenue recognized	(512)
Balance, September 30, 2021	$	~~407~~

~~Balance, December 31, 2019~~	$	~~377~~
~~Additions~~	~~598~~
~~Revenue recognized~~	~~(614)~~
~~Balance, September 30, 2020~~	$	~~361~~408

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 customers 473 256

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	September 30, 2022		December 31, 2021
Contract balances:
Contract assets	$	182	$	157
Accounts receivable from contracts with customers	631		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 ~~component~~components 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) 2022 2023 Thereafter Total
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)		2023		2024		Thereafter		Total
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, 2021		December 31, 2020			September 30, 2022		December 31, 2021
		Notional Volume	Maturity	Notional Volume	Maturity		Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives	Mark-to-Market Derivatives					Mark-to-Market Derivatives
(Trading)	(Trading)					(Trading)
Natural Gas (BBtu):	Natural Gas (BBtu):					Natural Gas (BBtu):
Fixed Swaps/Futures						Fixed Swaps/Futures	763	2022-2023	585	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/Futures		475	2021-2023	1,603	2021-2022

Power (Megawatt):	Power (Megawatt):					Power (Megawatt):
Forwards	Forwards	712,400	2021-2029	1,392,400	2021-2029	Forwards	455,200	2023-2029	653,000	2023-2029
Futures	Futures	(640,800)	2021-2022	18,706	2021-2022	Futures	(281,905)	2022-2023	(604,920)	2022-2023
Options – Puts	Options – Puts	290,400	2021-2022	519,071	2021	Options – Puts	119,200	2022-2023	(7,859)	2022
Options – Calls	Options – Calls	36,704	2021-2022	2,343,293	2021	Options – 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/NYMEX	Basis Swaps IFERC/NYMEX	(8,893)	2021-2022	(29,173)	2021-2022	Basis Swaps IFERC/NYMEX	36,443	2022-2024	6,738	2022-2023
Swing Swaps IFERC	Swing Swaps IFERC	(48,675)	2021-2022	11,208	2021	Swing Swaps IFERC	(217,515)	2022-2024	(106,333)	2022-2023
Fixed Swaps/Futures	Fixed Swaps/Futures	(45,588)	2021-2023	(53,575)	2021-2022	Fixed Swaps/Futures	(31,383)	2022-2024	(63,898)	2022-2023
Forward Physical Contracts	Forward Physical Contracts	(10,071)	2021	(11,861)	2021	Forward Physical Contracts	(27,603)	2022-2024	(5,950)	2023

NGLs (MBbls) – Forwards/Swaps	NGLs (MBbls) – Forwards/Swaps	2,785	2021-2023	(5,840)	2021-2022	NGLs (MBbls) – Forwards/Swaps	4,832	2022-2025	8,493	2022-2024
Crude (MBbls) – Forwards/Swaps						Crude (MBbls) – Forwards/Swaps	3,732	2022-2023	3,672	2022-2023
Refined Products (MBbls) – Futures	Refined Products (MBbls) – Futures	(3,272)	2021-2023	(2,765)	2021	Refined Products (MBbls) – Futures	(2,604)	2022-2024	(3,349)	2022-2023
Crude (MBbls) – Forwards/Swaps		1,693	2021-2022	—	—

Fair Value Hedging Derivatives	Fair Value Hedging Derivatives					Fair Value Hedging Derivatives
(Non-Trading)	(Non-Trading)					(Non-Trading)
Natural Gas (BBtu):	Natural Gas (BBtu):					Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(21,255)	2021	(30,113)	2021	Basis Swaps IFERC/NYMEX	(34,183)	2022	(40,533)	2022
Fixed Swaps/Futures	Fixed Swaps/Futures	(21,255)	2021	(30,113)	2021	Fixed Swaps/Futures	(34,183)	2022	(40,533)	2022
Hedged Item – Inventory	Hedged Item – Inventory	21,255	2021	30,113	2021	Hedged Item – Inventory	34,183	2022	40,533	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:

Term

Type(1)

Notional Amount Outstanding

Term

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)

Forward-starting to pay a fixed rate of 3.80% and receive a floating rate

400

July 2022(2)

Forward-starting to pay an average fixed rate of 3.80% and receive a floating rate

—

400

July 2023(2)

Forward-starting to pay a fixed rate of 3.78% and receive a floating rate

200

—

July 2023(2)

Forward-starting to pay an average fixed rate of 3.845% and receive a floating rate

400

200

July 2024(2)

Forward-starting to pay a fixed rate of 3.88% and receive a floating rate

200

—

July 2024(2)

Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate

400

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 Instruments									Fair Value of Derivative Instruments
		Asset Derivatives				Liability Derivatives					Asset Derivatives				Liability 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)	$	2	$	25	$	(20)	$	(32)	Commodity derivatives (margin deposits)	$	113	$	46	$	(77)	$	(3)
		2		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 derivatives	Commodity derivatives	702		53		(661)		(71)		Commodity derivatives	104		53		(94)		(52)
Interest rate derivatives	Interest rate derivatives	—		—		(376)		(448)		Interest rate derivatives	—		—		(84)		(387)
		1,032		143		(1,437)		(685)			770		226		(667)		(595)
Total derivatives	Total 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 Derivatives				Liability Derivatives						Asset Derivatives				Liability Derivatives
		Balance Sheet Location	September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020			Balance Sheet Location	September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021
Derivatives without offsetting agreements	Derivatives without offsetting agreements	Derivative liabilities	$	—	$	—	$	(376)	$	(448)	Derivatives without offsetting agreements	Derivative liabilities	$	—	$	—	$	(84)	$	(387)
Derivatives in offsetting agreements:	Derivatives in offsetting agreements:										Derivatives in offsetting agreements:
OTC contracts	OTC contracts	Derivative assets (liabilities)	702		53		(661)		(71)		OTC contracts	Derivative assets (liabilities)	104		53		(94)		(52)
Broker cleared derivative contracts	Broker cleared derivative contracts	Other current assets (liabilities)	332		115		(420)		(198)		Broker cleared derivative contracts	Other current assets (liabilities)	779		219		(566)		(159)
Total gross derivatives	Total gross derivatives		1,034		168		(1,457)		(717)		Total gross derivatives		883		272		(744)		(598)
Offsetting agreements:	Offsetting agreements:										Offsetting agreements:

Counterparty netting	Counterparty netting	Derivative assets (liabilities)	(645)		(44)		645		44		Counterparty netting	Derivative assets (liabilities)	(85)		(43)		85		43
Counterparty netting	Counterparty netting	Other current assets (liabilities)	(327)		(64)		327		64		Counterparty netting	Other current assets (liabilities)	(410)		(150)		410		150
Total net derivatives	Total 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:


		Location	Amount of Gain (Loss) Recognized in Income on Derivatives									Location	Amount 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,
			2021		2020		2021		2020				2022		2021		2022		2021
Derivatives not designated as hedging instruments:	Derivatives not designated as hedging instruments:										Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Commodity derivatives – Trading	Cost of products sold	$	14	$	4	$	12	$	15	Commodity derivatives – Trading	Cost of products sold	$	22	$	14	$	50	$	12
Commodity derivatives – Non-trading	Commodity derivatives – Non-trading	Cost of products sold	(71)		(44)		(206)		53		Commodity derivatives – Non-trading	Cost of products sold	186		(71)		(6)		(206)

Interest rate derivatives	Interest rate derivatives	Gains (losses) on interest rate derivatives	1		55		72		(277)		Interest rate derivatives	Gains (losses) on interest rate derivatives	60		1		303		72

Total	Total		$	(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.

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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,
		2021		2020		2021		2020			2022		2021		2022		2021
Revenues:	Revenues:									Revenues:
Intrastate transportation and storage:	Intrastate transportation and storage:									Intrastate transportation and storage:
Revenues from external customers	Revenues from external customers	$	1,112	$	614	$	5,940	$	1,615	Revenues from external customers	$	2,081	$	1,112	$	5,550	$	5,940
Intersegment revenues	Intersegment revenues	105		40		1,126		148		Intersegment revenues	302		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 customers	Revenues from external customers	412		466		1,317		1,365		Revenues from external customers	533		412		1,591		1,317
Intersegment revenues	Intersegment revenues	6		5		33		15		Intersegment revenues	16		6		54		33
		418		471		1,350		1,380			549		418		1,645		1,350
Midstream:	Midstream:									Midstream:
Revenues from external customers	Revenues from external customers	560		585		1,709		1,477		Revenues from external customers	1,115		560		3,399		1,709
Intersegment revenues	Intersegment revenues	2,359		792		6,081		2,088		Intersegment revenues	3,756		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 customers	Revenues from external customers	4,499		2,207		11,726		5,991		Revenues from external customers	5,169		4,499		16,644		11,726
Intersegment revenues	Intersegment revenues	763		416		2,048		1,466		Intersegment revenues	906		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 customers	Revenues from external customers	4,577		2,849		12,497		8,873		Revenues from external customers	6,415		4,577		19,640		12,497
Intersegment revenues	Intersegment revenues	1		1		1		4		Intersegment revenues	1		1		2		1
		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 customers	Revenues from external customers	4,772		2,801		12,626		8,104		Revenues from external customers	6,577		4,772		19,767		12,626
Intersegment revenues	Intersegment revenues	7		4		16		53		Intersegment revenues	17		7		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 customers	Revenues from external customers	156		158		464		500		Revenues from external customers	176		156		503		464
Intersegment revenues	Intersegment revenues	3		3		9		9		Intersegment revenues	3		3		11		9
		159		161		473		509			179		159		514		473
All other:	All other:									All other:
Revenues from external customers	Revenues from external customers	576		275		2,481		995		Revenues from external customers	873		576		2,281		2,481
Intersegment revenues	Intersegment revenues	120		92		303		377		Intersegment revenues	211		120		480		303
		696		367		2,784		1,372			1,084		696		2,761		2,784
Eliminations	Eliminations	(3,364)		(1,353)		(9,617)		(4,160)		Eliminations	(5,212)		(3,364)		(14,971)		(9,617)
Total revenues	Total 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,
		2021		2020		2021		2020			2022		2021		2022		2021
Segment Adjusted EBITDA:	Segment Adjusted EBITDA:									Segment Adjusted EBITDA:
Intrastate transportation and storage	Intrastate transportation and storage	$	172	$	203	$	3,209	$	630	Intrastate transportation and storage	$	301	$	172	$	963	$	3,209
Interstate transportation and storage	Interstate transportation and storage	334		425		1,118		1,232		Interstate transportation and storage	409		334		1,259		1,118
Midstream	Midstream	556		530		1,321		1,280		Midstream	868		556		2,578		1,321
NGL and refined products transportation and services	NGL and refined products transportation and services	706		762		2,089		2,099		NGL and refined products transportation and services	634		706		2,097		2,089
Crude oil transportation and services	Crude oil transportation and services	496		631		1,490		1,741		Crude oil transportation and services	461		496		1,616		1,490
Investment in Sunoco LP	Investment in Sunoco LP	198		189		556		580		Investment in Sunoco LP	276		198		681		556
Investment in USAC	Investment in USAC	99		104		299		315		Investment in USAC	109		99		313		299
All other	All other	18		22		153		62		All other	30		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 amortization	Depreciation, 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 capitalized	Interest 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 derivatives		1		55		72		(277)
Impairment losses and other										Impairment losses and other	(86)		—		(386)		(11)
Gains on interest rate derivatives										Gains on interest rate derivatives	60		1		303		72
Non-cash compensation expense	Non-cash compensation expense	(26)		(30)		(81)		(93)		Non-cash compensation expense	(27)		(26)		(88)		(81)
Unrealized gains (losses) on commodity risk management activities	Unrealized gains (losses) on commodity risk management activities	(19)		(30)		74		(27)		Unrealized gains (losses) on commodity risk management activities	76		(19)		130		74
Inventory valuation adjustments (Sunoco LP)	Inventory valuation adjustments (Sunoco LP)	9		11		168		(126)		Inventory valuation adjustments (Sunoco LP)	(40)		9		81		168
Losses on extinguishments of debt	Losses on extinguishments of debt	—		—		(8)		(62)		Losses on extinguishments of debt	—		—		—		(8)
Adjusted EBITDA related to unconsolidated affiliates	Adjusted 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 affiliates		71		(32)		191		46
Impairment of investment in an unconsolidated affiliate		—		(129)		—		(129)
Equity in earnings of unconsolidated affiliates										Equity in earnings of unconsolidated affiliates	68		71		186		191

Other, net	Other, net	11		53		—		(48)		Other, net	19		11		(65)		—
Income (loss) before income tax expense		984		(360)		5,690		(525)
Income before income tax expense										Income before income tax expense	1,404		984		4,590		5,690
Income tax expense	Income tax expense	(77)		(41)		(234)		(168)		Income tax expense	(82)		(77)		(159)		(234)

Net income (loss)		$	907	$	(401)	$	5,456	$	(693)
Net income										Net 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, ~~2020~~2021 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, ~~2020~~2021 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 Issuance~~Woodford 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 900,000~~completed 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 impacts~~cash proceeds to ~~the Partnership’s consolidated net income and Adjusted EBITDA and also affected the results~~Energy 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 Acquisition~~Spindletop Assets Purchase

~~On February 16, 2021,~~In March 2022, the Partnership ~~entered into a definitive merger agreement to acquire Enable. Under~~purchased the ~~terms of the merger agreement, Enable’s common unitholders will receive 0.8595 of~~membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an ~~ET common unit in exchange~~underground 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~~

•~~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.”

~~Sunoco LP’s Acquisitions~~

~~In September and October 2021,~~2022, Sunoco LP ~~acquired~~completed the acquisition of a ~~total of nine refined product terminals~~transmix processing and terminal facility in ~~two separate transactions~~Huntington, Indiana for ~~approximately $256~~ $252 million.

Quarterly Cash Distribution

In October ~~2021, ET~~2022, Energy Transfer announced its quarterly distribution of ~~$0.1525~~$0.265 per unit ($~~0.61~~1.06 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's~~FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.

Even without application of the FERC’s recent rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, ~~although changes in these components may tend~~but also other pipeline costs that will continue to ~~decrease our cost-of-service rate, other components in the cost-of-service rate calculation may increase~~affect 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 NGA~~general 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 to~~opposing 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 NOI~~2022 Policy Statements that ~~will~~might affect our natural gas pipeline ~~business~~or 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 ~~this~~these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Common Carrier Regulation

The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many

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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. ~~Requests~~The FERC received requests for rehearing of ~~the~~its December 17, 2020 order ~~were filed~~and 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 determination~~new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties have sought rehearing of the ~~index rate coupled~~January 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 of~~DC 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

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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Segment Adjusted EBITDA:	Segment Adjusted EBITDA:													Segment Adjusted EBITDA:
Intrastate transportation and storage	Intrastate 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 storage	Interstate transportation and storage	334		425		(91)		1,118		1,232		(114)		Interstate transportation and storage	409		334		75		1,259		1,118		141
Midstream	Midstream	556		530		26		1,321		1,280		41		Midstream	868		556		312		2,578		1,321		1,257
NGL and refined products transportation and services	NGL and refined products transportation and services	706		762		(56)		2,089		2,099		(10)		NGL and refined products transportation and services	634		706		(72)		2,097		2,089		8
Crude oil transportation and services	Crude oil transportation and services	496		631		(135)		1,490		1,741		(251)		Crude oil transportation and services	461		496		(35)		1,616		1,490		126
Investment in Sunoco LP	Investment in Sunoco LP	198		189		9		556		580		(24)		Investment in Sunoco LP	276		198		78		681		556		125
Investment in USAC	Investment in USAC	99		104		(5)		299		315		(16)		Investment in USAC	109		99		10		313		299		14
All other	All other	18		22		(4)		153		62		91		All other	30		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 amortization	Depreciation, 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 capitalized	Interest 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 derivatives		1		55		(54)		72		(277)		349
Impairment losses and other														Impairment losses and other	(86)		—		(86)		(386)		(11)		(375)
Gains on interest rate derivatives														Gains on interest rate derivatives	60		1		59		303		72		231
Non-cash compensation expense	Non-cash compensation expense	(26)		(30)		4		(81)		(93)		12		Non-cash compensation expense	(27)		(26)		(1)		(88)		(81)		(7)
Unrealized gains (losses) on commodity risk management activities	Unrealized gains (losses) on commodity risk management activities	(19)		(30)		11		74		(27)		101		Unrealized gains (losses) on commodity risk management activities	76		(19)		95		130		74		56
Inventory valuation adjustments (Sunoco LP)	Inventory valuation adjustments (Sunoco LP)	9		11		(2)		168		(126)		294		Inventory valuation adjustments (Sunoco LP)	(40)		9		(49)		81		168		(87)
Losses on extinguishments of debt	Losses on extinguishments of debt	—		—		—		(8)		(62)		54		Losses on extinguishments of debt	—		—		—		—		(8)		8
Adjusted EBITDA related to unconsolidated affiliates	Adjusted 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 affiliates		71		(32)		103		191		46		145
Impairment of investment in an unconsolidated affiliate		—		(129)		129		—		(129)		129
Equity in earnings of unconsolidated affiliates														Equity in earnings of unconsolidated affiliates	68		71		(3)		186		191		(5)

Other, net	Other, net	11		53		(42)		—		(48)		48		Other, net	19		11		8		(65)		—		(65)
Income (loss) before income tax expense		984		(360)		1,344		5,690		(525)		6,215
Income before income tax expense														Income before income tax expense	1,404		984		420		4,590		5,690		(1,100)
Income tax expense	Income 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 income														Net income	$	1,322	$	907	$	415	$	4,431	$	5,456	$	(1,025)

Adjusted EBITDA (consolidated). For the three months ended September 30, ~~2021~~2022 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 increases~~both of which were ~~also~~ primarily due to the ~~impacts~~impact 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, ~~2021~~2022 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, ~~2021~~2022 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, ~~decreased~~increased for the three ~~and nine~~ months ended September 30, ~~2021~~2022 compared to the same ~~periods~~period 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 ~~$30~~an increase in the weighted average interest rate on long-term debt.

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 due~~2022 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; and~~its 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, ~~2021~~2022 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, increases~~2022 a decrease in fuel prices ~~reduced~~increased 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 ~~nine~~three 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 decline~~2022 and September 30, 2021, an increase in fuel prices ~~increased~~reduced lower of cost or market reserve requirements ~~for the period~~ by ~~$126~~$81 million and $168 million, respectively, resulting in ~~an adverse impact~~favorable impacts to net income.

Losses on Extinguishments of Debt. ~~During~~For the nine months ended September 30, 2021, the ~~losses~~loss on ~~extinguishments~~extinguishment of debt ~~also included~~was 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, ~~2021~~2022 compared to the same ~~periods~~period 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Equity in earnings (losses) of unconsolidated affiliates:	Equity in earnings (losses) of unconsolidated affiliates:													Equity in earnings (losses) of unconsolidated affiliates:
Citrus	Citrus	$	44	$	50	$	(6)	$	123	$	127	$	(4)	Citrus	$	36	$	44	$	(8)	$	109	$	123	$	(14)
FEP (1)		—		(106)		106		—		(158)		158

MEP	MEP	(5)		(1)		(4)		(12)		(3)		(9)		MEP	(1)		(5)		4		(7)		(12)		5
White Cliffs	White Cliffs	(1)		2		(3)		—		19		(19)		White Cliffs	—		(1)		1		1		—		1
Explorer														Explorer	8		9		(1)		17		20		(3)
Other	Other	33		23		10		80		61		19		Other	25		24		1		66		60		6
Total equity in earnings (losses) of unconsolidated affiliates		$	71	$	(32)	$	103	$	191	$	46	$	145
Total equity in earnings of unconsolidated affiliates														Total 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):
Citrus	Citrus	$	87	$	96	$	(9)	$	251	$	264	$	(13)	Citrus	$	86	$	87	$	(1)	$	245	$	251	$	(6)
FEP		—		19		(19)		—		57		(57)

MEP	MEP	4		8		(4)		14		23		(9)		MEP	8		4		4		19		14		5
White Cliffs	White Cliffs	4		11		(7)		14		38		(24)		White Cliffs	5		4		1		15		14		1
Explorer														Explorer	12		12		—		28		31		(3)
Other	Other	46		35		11		121		98		23		Other	36		34		2		102		90		12
Total Adjusted EBITDA related to unconsolidated affiliates	Total Adjusted EBITDA related to unconsolidated affiliates	$	141	$	169	$	(28)	$	400	$	480	$	(80)	Total Adjusted EBITDA related to unconsolidated affiliates	$	147	$	141	$	6	$	409	$	400	$	9

Distributions received from unconsolidated affiliates:	Distributions received from unconsolidated affiliates:													Distributions received from unconsolidated affiliates:
Citrus	Citrus	$	106	$	48	$	58	$	191	$	155	$	36	Citrus	$	52	$	106	$	(54)	$	133	$	191	$	(58)
FEP		—		20		(20)		4		55		(51)

MEP	MEP	1		4		(3)		9		22		(13)		MEP	4		1		3		14		9		5
White Cliffs	White Cliffs	5		2		3		25		25		—		White Cliffs	5		5		—		15		25		(10)
Explorer														Explorer	6		6		—		20		20		—
Other	Other	26		24		2		73		63		10		Other	27		20		7		66		57		9
Total distributions received from unconsolidated affiliates	Total 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.

~~Table~~Ta b le of Contents

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 the~~The 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 ~~nine~~three 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
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)
Revenues	Revenues	$	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 sold	Cost of products sold	978		434		544		3,636		985		2,651		Cost of products sold	1,994		978		1,016		5,008		3,636		1,372
Segment margin	Segment margin	239		220		19		3,430		778		2,652		Segment margin	389		239		150		1,210		3,430		(2,220)
Unrealized (gains) losses on commodity risk management activities	Unrealized (gains) losses on commodity risk management activities	(1)		23		(24)		(18)		(16)		(2)		Unrealized (gains) losses on commodity risk management activities	12		(1)		13		17		(18)		35
Operating expenses, excluding non-cash compensation expense	Operating 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 expense	Selling, 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 affiliates	Adjusted EBITDA related to unconsolidated affiliates	6		7		(1)		19		19		—		Adjusted EBITDA related to unconsolidated affiliates	5		6		(1)		18		19		(1)
Other	Other	—		2		(2)		2		2		—		Other	—		—		—		6		2		4
Segment Adjusted EBITDA	Segment 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, ~~2021~~2022 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, ~~2021~~2022 compared to the same period last year, transported volumes ~~decreased~~increased primarily due to the ~~bankruptcy filing~~acquisition 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Transportation fees	Transportation 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		5
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	8		5		3		1,558		40		1,518		Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	—		8		(8)		40		1,558		(1,518)
Unrealized gains on commodity risk management activities and fair value inventory adjustments		1		(23)		24		18		16		2
Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustments														Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustments	(11)		1		(12)		(16)		18		(34)
Total segment margin	Total 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, ~~2021~~2022 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment ~~decreased~~increased due to the net ~~effects~~impacts of the following:

•~~a decrease~~an increase of ~~$36~~$100 million in realized natural gas sales and other primarily due to ~~lower optimization volumes with shifts~~higher optimization;

•an increase of $40 million in transportation fees primarily due to ~~long-term third-party contracts~~fees 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 of~~retained fuel ~~consumption due~~revenues 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 fees~~operating expenses primarily due to ~~increased firm transportation volumes~~a $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 revenues~~selling, general and administrative expenses primarily due to ~~higher natural gas prices; and~~

~~Table~~the addition of ~~Contents~~

•Enable~~an increase of $3 million in realized storage margin due to higher storage optimization.~~.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2021~~2022 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,
2021 2020 Change 2021 2020 Change
Natural gas transported (BBtu/d) 9,917 10,387 (470) 9,769 10,422 (653)
Natural gas sold (BBtu/d) 16 15 1 18 16 2
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 affiliates 91 122 (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 ~~revenues~~realized storage margin primarily due to ~~a $37 million decline resulting~~higher physical storage margin from ~~shipper contract expirations on our Tiger system and an $18 million decline due to a shipper bankruptcy~~withdrawals 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 increase~~a decrease of $5$744 million in ~~operating expenses~~realized natural gas sales and other primarily due to ~~a $7 million increase from the revaluation of system~~natural 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 losses~~sales 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; and~~legal expenses; partially offset by

~~Table of Contents~~

•~~a decrease~~an increase of ~~$31~~$71 million in ~~Adjusted EBITDA related to unconsolidated affiliates~~transportation fees primarily due to ~~a $19~~fees on the recently acquired Enable Oklahoma Intrastate Transmission system, partially offset by fees related to Winter Storm Uri in the prior period; and

•an increase of $5 million ~~decrease from our Fayetteville Express Pipeline joint venture as a result~~in retained fuel revenues related to natural gas prices.

Interstate Transportation and Storage


	Three Months Ended September 30,						Nine Months Ended September 30,
	2022		2021		Change		2022		2021		Change
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	3		—		3		24		—		24
Segment margin	546		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 affiliates	106		91		15		293		265		28

Other	13		(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 from~~Enable Acquisition, higher utilization on our ~~Citrus joint venture~~Tiger system due to ~~a contractual rate adjustment~~increased production in the Haynesville Shale and ~~a $3 million decrease from~~higher volumes on our ~~Midcontinent Express Pipeline joint venture~~Trunkline system due to ~~lower rates on short-term capacity.~~increased demand.

Segment Adjusted EBITDA. For the ~~nine~~three months ended September 30, ~~2021~~2022 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment ~~decreased~~increased due to the net impacts of the following:

•~~a decrease~~an increase of ~~$30~~$128 million in ~~revenues~~segment margin primarily due to a ~~$97~~$137 million ~~decline resulting~~increase as a result of higher volumes from ~~shipper contract expirations on our Tiger system~~the Enable Acquisition and increased production in the Haynesville Shale and Permian Basin and a ~~$37~~$2 million ~~decline~~increase 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 ~~increase~~decrease 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 ~~decrease~~increase from our ~~Fayetteville~~Midcontinent 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 ~~expiration~~realization in the current period of ~~foundation~~certain amounts related to a shipper ~~contracts,~~bankruptcy that occurred in a ~~$13~~prior 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 venture~~in 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
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		8		NGLs produced (MBbls/d)	814		667		147		795		624		171
Equity NGLs (MBbls/d)	Equity NGLs (MBbls/d)	37		32		5		35		35		—		Equity NGLs (MBbls/d)	43		37		6		44		35		9
Revenues	Revenues	$	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 sold	Cost of products sold	2,153		668		1,485		5,864		1,716		4,148		Cost of products sold	3,678		2,153		1,525		10,418		5,864		4,554
Segment margin	Segment margin	766		709		57		1,926		1,849		77		Segment margin	1,193		766		427		3,428		1,926		1,502

Operating expenses, excluding non-cash compensation expense	Operating 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 expense	Selling, 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 affiliates	Adjusted EBITDA related to unconsolidated affiliates	8		9		(1)		23		23		—		Adjusted EBITDA related to unconsolidated affiliates	5		8		(3)		20		23		(3)
Other	Other	1		2		(1)		3		3		—		Other	—		1		(1)		38		3		35
Segment Adjusted EBITDA	Segment 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, ~~2021~~2022 compared to the same ~~period~~periods 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/Panhandle~~all 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Gathering and processing fee-based revenues	Gathering 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 processing	Non-fee-based contracts and processing	231		67		164		371		174		197		Non-fee-based contracts and processing	387		231		156		1,180		371		809

Total segment margin	Total 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, ~~2021~~2022 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 contracts~~Enable 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 ~~employee~~incremental operating expenses related to the Enable assets acquired in December 2021 and an $18 million increase in maintenance project costs and ~~$6 million~~materials 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, ~~2021~~2022 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 ~~throughput~~production in the Permian ~~region~~ and ~~the ramp-up of recently completed assets in the Northeast region; partially offset by~~South Texas regions;

•~~a decrease~~an increase of $143 million in non-fee-based margin due to the impacts of Winter Storm ~~Uri;~~Uri in the prior period; and

•~~a decrease~~an 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 contracts~~Enable Acquisition in ~~the Ark-La-Tex region in the third quarter of 2020,~~December 2021, as well as ~~volume declines~~increased 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 ~~employee~~incremental operating expenses related to the Enable assets acquired in December 2021, a $36 million increase in maintenance project costs ~~offset by~~and materials in the South Texas and Permian regions, a ~~decrease of~~ $9 million increase in ~~outside services~~fuel 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
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		7		815		839		(24)		NGL fractionation volumes (MBbls/d)	940		884		56		895		815		80
Revenues	Revenues	$	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 sold	Cost of products sold	4,347		1,712		2,635		11,035		4,916		6,119		Cost of products sold	5,044		4,347		697		16,921		11,035		5,886
Segment margin	Segment margin	915		911		4		2,739		2,541		198		Segment margin	1,031		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 activities														Unrealized gains on commodity risk management activities	(126)		(2)		(124)		(158)		(71)		(87)
Operating expenses, excluding non-cash compensation expense	Operating 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 expense	Selling, 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 affiliates	Adjusted EBITDA related to unconsolidated affiliates	26		22		4		75		63		12		Adjusted EBITDA related to unconsolidated affiliates	27		26		1		71		75		(4)

Other	Other	1		—		1		1		—		1		Other	—		1		(1)		—		1		(1)
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	706	$	762	$	(56)	$	2,089	$	2,099	$	(10)	Segment Adjusted EBITDA	$	634	$	706	$	(72)	$	2,097	$	2,089	$	8

Volumes. For the three and nine months ended September 30, ~~2021~~2022 compared to the same periods last year, NGL transportation volumes increased primarily due to higher volumes from the ~~initiation of service~~Permian 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, ~~2021~~2022 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, ~~2021~~2022 compared to the same periods last year primarily due to ~~the previously mentioned start of new~~higher volumes on our export pipelines and refined product demand recovery.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility ~~decreased~~increased for the three and nine months ended September 30, ~~2021~~2022 compared to the same ~~period~~periods last year ~~primarily~~ due to ~~lower NGL volumes feeding~~increased 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Transportation margin	Transportation margin	$	514	$	494	$	20	$	1,495	$	1,419	$	76	Transportation margin	$	553	$	514	$	39	$	1,552	$	1,495	$	57
Fractionators and refinery services margin	Fractionators and refinery services margin	182		189		(7)		510		541		(31)		Fractionators and refinery services margin	227		182		45		627		510		117
Terminal services margin	Terminal services margin	166		130		36		470		410		60		Terminal services margin	179		166		13		521		470		51
Storage margin	Storage margin	63		63		—		200		181		19		Storage margin	72		63		9		211		200		11
Marketing margin	Marketing margin	(12)		46		(58)		(7)		24		(31)		Marketing margin	(126)		(12)		(114)		(81)		(7)		(74)
Unrealized gains (losses) on commodity risk management activities		2		(11)		13		71		(34)		105
Unrealized gains on commodity risk management activities														Unrealized gains on commodity risk management activities	126		2		124		158		71		87
Total segment margin	Total segment margin	$	915	$	911	$	4	$	2,739	$	2,541	$	198	Total segment margin	$	1,031	$	915	$	116	$	2,988	$	2,739	$	249

Ta b le of Contents

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, 2021~~2022 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 ~~downtime~~higher 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 2021~~Texas 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 was~~Mariner 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 activity~~higher 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 reductions~~a $2 million increase in ~~2020; partially offset by~~overhead 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 ~~due~~resulting 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 ~~export~~exported 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 $81~~intrasegment 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 Texas~~on our Mariner West pipeline due to ~~Winter Storm Uri related production outages~~customer 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 ethane~~from higher export ~~fees~~volumes 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 to~~from 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 throughput~~a $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 recovery~~a $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 ~~resulting~~in component product storage fees; partially offset by

Ta b le of Contents

•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 expiration~~maintenance 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 margin~~selling, 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 increase~~a decrease of ~~$12~~$4 million in Adjusted EBITDA related to unconsolidated affiliates due to a $7$3 million ~~increase primarily resulting~~decrease from ~~higher throughput~~lower volumes on the Explorer pipeline ~~due to COVID-19 demand recovery~~ and a $5$2 million ~~increase~~decrease from ~~higher~~lower 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
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
Revenues	Revenues	$	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 sold	Cost of products sold	3,918		2,096		1,822		10,520		6,704		3,816		Cost of products sold	5,627		3,918		1,709		17,347		10,520		6,827
Segment margin	Segment margin	660		754		(94)		1,978		2,173		(195)		Segment margin	789		660		129		2,295		1,978		317
Unrealized (gains) losses on commodity risk management activities	Unrealized (gains) losses on commodity risk management activities	14		(1)		15		12		9		3		Unrealized (gains) losses on commodity risk management activities	2		14		(12)		(4)		12		(16)
Operating expenses, excluding non-cash compensation expense	Operating 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 expense	Selling, 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 affiliates	Adjusted EBITDA related to unconsolidated affiliates	7		9		(2)		15		32		(17)		Adjusted EBITDA related to unconsolidated affiliates	1		7		(6)		3		15		(12)

Other	Other	1		9		(8)		1		10		(9)		Other	—		1		(1)		1		1		—
Segment Adjusted EBITDA	Segment 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, ~~2021~~2022 compared to the same ~~period~~periods last year, crude transportation volumes were higher on our Texas pipeline system and Bakken ~~pipeline,~~Pipeline, driven by ~~a recovery in~~continuing crude oil production growth in these regions as

~~Table of Contents~~

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 favorable~~primarily due to increased crude ~~oil differentials for shippers. Volumes also benefited~~supply from ~~a full quarter of operations from our Cushing South pipeline.~~recent Strategic Petroleum Reserve sales. Crude ~~terminal~~Terminal volumes were higher due to ~~increased customer~~Strategic 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, ~~2021~~2022 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 decrease~~an 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 business~~increase due to ~~storage trading gains realized in the prior period, unfavorable crude inventory valuation adjustments, and less favorable pricing conditions impacting~~higher volumes on our Bakken Pipeline, a $28 million increase related to ~~Gulf Coast trading operations,~~assets acquired in 2021, a $6$45 million ~~decrease~~increase in throughput at our ~~crude~~Gulf Coast terminals ~~primarily driven by lower~~due 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 from~~increase on our Texas ~~crude~~ pipeline system due to ~~lower average tariff rates realized; partially~~higher 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, ~~2021~~2022 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment ~~decreased~~increased due to the net impacts of the following:

•~~a decrease~~an 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 ~~decrease~~increase 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 utilization~~higher 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.~~

~~Table~~the consolidation of ~~Contents~~certain 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Revenues	Revenues	$	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 sold	Cost of products sold	4,472		2,497		1,975		11,631		7,383		4,248		Cost of products sold	6,261		4,472		1,789		18,703		11,631		7,072
Segment margin	Segment margin	307		308		(1)		1,011		774		237		Segment margin	333		307		26		1,108		1,011		97
Unrealized (gains) losses on commodity risk management activities	Unrealized (gains) losses on commodity risk management activities	2		(6)		8		(5)		—		(5)		Unrealized (gains) losses on commodity risk management activities	23		2		21		3		(5)		8
Operating expenses, excluding non-cash compensation expense	Operating 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 expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(23)		(24)		1		(67)		(76)		9		Selling, general and administrative expenses, excluding non-cash compensation expense	(29)		(23)		(6)		(78)		(67)		(11)
Adjusted EBITDA related to unconsolidated affiliates	Adjusted EBITDA related to unconsolidated affiliates	3		2		1		7		7		—		Adjusted EBITDA related to unconsolidated affiliates	2		3		(1)		7		7		—
Inventory valuation adjustments	Inventory valuation adjustments	(9)		(11)		2		(168)		126		(294)		Inventory valuation adjustments	40		(9)		49		(81)		(168)		87
Other	Other	3		4		(1)		14		14		—		Other	5		3		2		15		14		1
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	198	$	189	$	9	$	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, ~~2021~~2022 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 ~~sales~~gross 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 ~~profit~~profit; 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, ~~2021~~2022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment ~~decreased~~increased due to the net impacts of the following:

•~~a decrease~~an increase in the gross profit on motor fuel sales of ~~$62~~$126 million primarily due to a ~~14.8% decrease~~17.3% increase in gross profit per gallon sold ~~partially offset by~~and 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 decrease~~an increase in operating expenses and selling, general and administrative expenses of ~~$38~~$68 million primarily due to ~~lower~~higher 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Revenues	Revenues	$	159	$	161	$	(2)	$	473	$	509	$	(36)	Revenues	$	179	$	159	$	20	$	514	$	473	$	41
Cost of products sold	Cost of products sold	19		20		(1)		61		62		(1)		Cost of products sold	28		19		9		78		61		17
Segment margin	Segment margin	140		141		(1)		412		447		(35)		Segment margin	151		140		11		436		412		24

Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(31)		(27)		(4)		(83)		(92)		9		Operating expenses, excluding non-cash compensation expense	(31)		(31)		—		(90)		(83)		(7)
Selling, general and administrative expenses, excluding non-cash compensation expense	Selling, 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 EBITDA	Segment 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.

~~Table of Contents~~

Segment Adjusted EBITDA. For the three months ended September 30, ~~2021~~2022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment ~~decreased~~increased primarily due to ~~the following:~~

•~~a decrease~~an 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 taxes~~contract 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, ~~2021~~2022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment ~~decreased~~increased primarily due to the net impacts of the following:

•~~a decrease~~an increase of ~~$35~~$24 million in segment margin primarily due to ~~lower~~an 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 decrease~~an increase of $9$7 million in operating expenses primarily ~~driven by a $7 million decrease~~due 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 primarily~~an increase due to sales tax refunds received in ~~2021; and~~the prior period.

•

~~a decrease~~Ta b le 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,
		2021		2020		Change		2021		2020		Change			2022		2021		Change		2022		2021		Change
Revenues	Revenues	$	696	$	367	$	329	$	2,784	$	1,372	$	1,412	Revenues	$	1,084	$	696	$	388	$	2,761	$	2,784	$	(23)
Cost of products sold	Cost of products sold	652		318		334		2,464		1,110		1,354		Cost of products sold	1,052		652		400		2,548		2,464		84
Segment margin	Segment margin	44		49		(5)		320		262		58		Segment margin	32		44		(12)		213		320		(107)
Unrealized losses on commodity risk management activities	Unrealized losses on commodity risk management activities	6		3		3		8		—		8		Unrealized losses on commodity risk management activities	13		6		7		12		8		4
Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(29)		(35)		6		(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 expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(13)		(23)		10		(71)		(80)		9		Selling, general and administrative expenses, excluding non-cash compensation expense	(11)		(13)		2		(44)		(71)		27
Adjusted EBITDA related to unconsolidated affiliates	Adjusted EBITDA related to unconsolidated affiliates	2		1		1		1		1		—		Adjusted EBITDA related to unconsolidated affiliates	2		2		—		3		1		2
Other and eliminations	Other and eliminations	8		27		(19)		13		(21)		34		Other and eliminations	11		8		3		40		13		27
Segment Adjusted EBITDA	Segment 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.~~

~~Table of Contents~~

~~Segment Adjusted EBITDA.~~ ~~For the nine months ended September 30, 2021~~2022 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 more~~a favorable ~~market pricing conditions;~~environment for physical gas trading and storage activities;

•an increase of $12 million due to ~~lower merger~~a 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 expiration~~higher 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 claims~~due 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 ~~2021~~2022 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):


		Growth				Maintenance					Growth				Maintenance
		Low		High		Low		High			Low		High		Low		High
Intrastate transportation and storage	Intrastate 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
Midstream	Midstream	445		470		115		120		Midstream	700		830		145		155
NGL and refined products transportation and services	NGL and refined products transportation and services	650		725		110		120		NGL and refined products transportation and services	375		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 expenditures	Total 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 ~~ownership~~share of the Bakken, Rover and Bayou Bridge pipeline ~~projects and our proportionate ownership of~~joint 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 budgeted~~spend between ~~$30~~$120 million and ~~$40~~$130 million in expansion capital expenditures for the full year ~~2021.~~

~~Table of Contents~~

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, ~~2021~~2022 compared to nine months ended September 30, ~~2020~~2021. Cash provided by operating activities during ~~2021~~2022 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 ~~loss~~income 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, ~~2021~~2022 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 ~~2021~~2022 and ~~2020~~2021 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 impairment~~respectively. In 2021, we also had losses on extinguishments of ~~investment in an unconsolidated affiliate~~debt 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, ~~2021~~2022 and ~~2020,~~2021, respectively. Interest capitalized was ~~$97~~$84 million and ~~$163~~$97 million for the nine months ended September 30, ~~2021~~2022 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, ~~2021~~2022 compared to nine months ended September 30, ~~2020.~~2021. Cash used in investing activities during ~~2021~~2022 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 ~~2021~~2022 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

~~Table~~$485 million in cash for the acquisitions of ~~Contents~~Woodford 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 Period							Capital Expenditures Recorded During Period
		Growth		Maintenance		Total			Growth		Maintenance		Total
Intrastate transportation and storage	Intrastate transportation and storage	$	17	$	24	$	41	Intrastate transportation and storage	$	75	$	37	$	112
Interstate transportation and storage	Interstate transportation and storage	24		72		96		Interstate transportation and storage	383		123		506
Midstream	Midstream	272		74		346		Midstream	512		129		641
NGL and refined products transportation and services	NGL and refined products transportation and services	508		77		585		NGL and refined products transportation and services	220		83		303
Crude oil transportation and services	Crude oil transportation and services	208		61		269		Crude oil transportation and services	115		81		196
Investment in Sunoco LP	Investment in Sunoco LP	70		22		92		Investment in Sunoco LP	76		21		97
Investment in USAC	Investment in USAC	26		15		41		Investment in USAC	99		20		119
All other (including eliminations)	All other (including eliminations)	48		26		74		All other (including eliminations)	19		33		52
Total capital expenditures	Total 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, ~~2021~~2022 compared to nine months ended September 30, ~~2020.~~2021. Cash used in financing activities during ~~2021~~2022 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 ~~increase~~decrease of ~~$358 million~~$6.00 billion for ~~2020. In 2021 and 2020, we paid debt issuance costs~~2021.

Ta b le 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 ~~2021~~2022 and ~~2020,~~2021, we paid distributions of ~~$1.38~~$2.12 billion and ~~$2.40~~$1.38 billion, respectively, to our partners. In ~~2021~~2022 and ~~2020,~~2021, we paid distributions of ~~$1.15~~$1.18 billion and ~~$1.28~~$1.15 billion, respectively, to noncontrolling interests. In ~~2021~~2022 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 in~~interests. During 2021, ~~compared to $203~~we 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 Notes	Transwestern Senior Notes	400		400		Transwestern Senior Notes	250		400
Panhandle Senior Notes		235		235
Panhandle Notes and Debentures						Panhandle Notes and Debentures	235		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 obligations	Sunoco LP Senior Notes and lease-related obligations	2,701		3,139		Sunoco LP Senior Notes and lease-related obligations	2,694		2,700
USAC Senior Notes	USAC Senior Notes	1,475		1,475		USAC Senior Notes	1,475		1,475
HFOTCO Tax Exempt Notes	HFOTCO Tax Exempt Notes	225		225		HFOTCO Tax Exempt Notes	225		225
Revolving credit facilities:	Revolving credit facilities:					Revolving credit facilities:
Sunoco LP Credit Facility	Sunoco LP Credit Facility	250		—		Sunoco LP Credit Facility	704		581
USAC Credit Facility	USAC Credit Facility	506		474		USAC Credit Facility	618		516
Energy Transfer Canada Revolving Credit Facility(2)	Energy Transfer Canada Revolving Credit Facility(2)	81		57		Energy Transfer Canada Revolving Credit Facility(2)	—		7
Energy Transfer Canada Term Loan A		252		261
Energy Transfer Canada KAPS Facility		51		—
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 debt	Other long-term debt	4		3		Other long-term debt	3		3
Net unamortized premiums, discounts, and fair value adjustments	Net unamortized premiums, discounts, and fair value adjustments	(14)		(10)		Net unamortized premiums, discounts, and fair value adjustments	199		238
Deferred debt issuance costs	Deferred debt issuance costs	(248)		(279)		Deferred debt issuance costs	(216)		(239)
Total debt	Total debt	45,471		51,438		Total debt	47,415		49,702
Less: current maturities of long-term debt	Less: current maturities of long-term debt	678		21		Less: current maturities of long-term debt	2		680

Long-term debt, less current maturities	Long-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 March~~For 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)The~~this balance includes $650 million aggregate principal amount of 3.625% Senior Notes due April 2022 included in current maturities of long-term ~~debt~~debt. 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 notes~~its 4.65% Senior Notes due February 2022 using proceeds from its Five-Year Credit Facility (defined below).

In April ~~1, 2021 and its $800~~2022, Dakota Access redeemed $650 million aggregate principal amount of ~~4.65% senior notes~~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.

~~During~~

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In August 2022, the ~~third quarter of 2021, ET issued~~Partnership 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 ~~$900~~fully redeemed $700 million aggregate principal amount of ~~5.875% senior notes~~its 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, utilizing~~October 2022 with proceeds from its Five-Year Credit Facility.

Credit Facilities and Commercial Paper

~~Term Loan~~

Five-Year Credit Facility

~~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, the~~2022, Sunoco ~~LP Credit Facility~~LP’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, ~~2021~~2022 was ~~$1.24 billion.~~$789 million. The weighted average interest rate on the total amount outstanding as of September 30, ~~2021~~2022 was ~~2.09%~~5.11%.

USAC Credit Facility

As of September 30, ~~2021, USAC~~2022, 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, ~~2021~~2022 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 appropriate~~General 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, ~~2020~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2020~~2021

February 8, ~~2021~~2022

February ~~19, 2021~~18, 2022

~~0.1525~~0.1750

March 31, ~~2021~~2022

May ~~11, 2021~~9, 2022

May 19, ~~2021~~2022

~~0.1525~~0.2000

June 30, ~~2021~~2022

August ~~6, 2021~~8, 2022

August 19, ~~2021~~2022

~~0.1525~~0.2300

September 30, ~~2021~~2022

November ~~5, 2021~~4, 2022

November ~~19, 2021~~21, 2022

~~0.1525~~0.2650

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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 Ended	Record Date	Payment Date	Series A (1)		Series B (1)		Series C		Series D		Series E		Series F (1)		Series G (1)		Series H (1)
December 31, 2021	February 1, 2022	February 15, 2022	$	31.250	$	33.125	$	0.4609	$	0.4766	$	0.475	$	—	$	—	$	—
March 31, 2022	May 2, 2022	May 16, 2022	—		—		0.4609		0.4766		0.475		33.750		35.625		32.500
June 30, 2022	August 1, 2022	August 15, 2022	31.250		33.125		0.4609		0.4766		0.475		—		—		—
September 30, 2022	November 1, 2022	November 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, ~~2020~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2020~~2021

February 8, ~~2021~~2022

February ~~19, 2021~~18, 2022

0.8255

March 31, ~~2021~~2022

May ~~11, 2021~~9, 2022

May 19, ~~2021~~2022

0.8255

June 30, ~~2021~~2022

August ~~6, 2021~~8, 2022

August 19, ~~2021~~2022

0.8255

September 30, ~~2021~~2022

November ~~5, 2021~~4, 2022

November ~~19, 2021~~18, 2022

0.8255

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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, ~~2020~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2020~~2021

January ~~25, 2021~~24, 2022

February ~~5, 2021~~4, 2022

0.525

March 31, ~~2021~~2022

April ~~26, 2021~~25, 2022

May ~~7, 2021~~6, 2022

0.525

June 30, ~~2021~~2022

July ~~26, 2021~~25, 2022

August ~~6, 2021~~5, 2022

0.525

September 30, ~~2021~~2022

October ~~25, 2021~~24, 2022

November ~~5, 2021~~4, 2022

0.525

~~ESTIMATES AND~~ CRITICAL ACCOUNTING ~~POLICIES~~ESTIMATES

The ~~selection and application of~~Partnership’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 that~~18, 2022. No significant changes have ~~been issued, but not yet adopted, that are expected~~occurred 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, ~~2020~~2021 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, ~~2020~~2021 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, 2021					December 31, 2020						September 30, 2022					December 31, 2021
		Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change		Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change			Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change		Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change
Mark-to-Market Derivatives	Mark-to-Market Derivatives											Mark-to-Market Derivatives
(Trading)	(Trading)											(Trading)
Natural Gas (BBtu):	Natural Gas (BBtu):											Natural Gas (BBtu):
Fixed Swaps/Futures												Fixed Swaps/Futures	763	$	—	$	—	585	$	—	$	—
Basis Swaps IFERC/NYMEX (1)	Basis Swaps IFERC/NYMEX (1)	(81,963)	$	10	$	1	(44,225)	$	2	$	5	Basis Swaps IFERC/NYMEX (1)	73,363	16		2		(66,665)	(5)		1
Fixed Swaps/Futures		475	1		—		1,603	—		—

Power (Megawatt):	Power (Megawatt):											Power (Megawatt):
Forwards	Forwards	712,400	15		—		1,392,400	4		—		Forwards	455,200	6		2		653,000	2		—
Futures	Futures	(640,800)	(7)		—		18,706	(1)		—		Futures	(281,905)	(2)		1		(604,920)	2		2
Options – Puts	Options – Puts	290,400	—		—		519,071	—		—		Options – Puts	119,200	—		—		(7,859)	—		—
Options – Calls	Options – Calls	36,704	(1)		—		2,343,293	1		—		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/NYMEX	Basis Swaps IFERC/NYMEX	(8,893)	(3)		—		(29,173)	—		1		Basis Swaps IFERC/NYMEX	36,443	(17)		3		6,738	1		1
Swing Swaps IFERC	Swing Swaps IFERC	(48,675)	4		1		11,208	(2)		—		Swing Swaps IFERC	(217,515)	24		1		(106,333)	32		31
Fixed Swaps/Futures	Fixed Swaps/Futures	(45,588)	(55)		25		(53,575)	6		31		Fixed Swaps/Futures	(31,383)	(37)		22		(63,898)	(24)		38
Forward Physical Contracts	Forward Physical Contracts	(10,071)	3		—		(11,861)	4		5		Forward Physical Contracts	(27,603)	6		14		(5,950)	1		—

NGLs (MBbls) – Forwards/Swaps	NGLs (MBbls) – Forwards/Swaps	2,785	20		44		(5,840)	(100)		39		NGLs (MBbls) – Forwards/Swaps	4,832	176		70		8,493	12		19
Crude (MBbls) – Forwards/Swaps												Crude (MBbls) – Forwards/Swaps	3,732	12		1		3,672	13		2
Refined Products (MBbls) – Futures	Refined Products (MBbls) – Futures	(3,272)	(3)		30		(2,765)	(8)		3		Refined Products (MBbls) – Futures	(2,604)	3		30		(3,349)	(15)		32
Crude (MBbls) – Forwards/Swaps		1,693	(13)		11		—	—		—

Fair Value Hedging Derivatives	Fair Value Hedging Derivatives											Fair Value Hedging Derivatives
(Non-Trading)	(Non-Trading)											(Non-Trading)
Natural Gas (BBtu):	Natural Gas (BBtu):											Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(21,255)	2		—		(30,113)	(1)		—		Basis Swaps IFERC/NYMEX	(34,183)	13		2		(40,533)	1		—
Fixed Swaps/Futures	Fixed Swaps/Futures	(21,255)	(20)		12		(30,113)	(6)		8		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):

Term

Type(1)

Notional Amount Outstanding

Term

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)

Forward-starting to pay a fixed rate of 3.80% and receive a floating rate

400

July 2022(2)

Forward-starting to pay an average fixed rate of 3.80% and receive a floating rate

—

400

July 2023(2)

Forward-starting to pay a fixed rate of 3.78% and receive a floating rate

200

—

July 2023(2)

Forward-starting to pay an average fixed rate of 3.845% and receive a floating rate

400

200

July 2024(2)

Forward-starting to pay a fixed rate of 3.88% and receive a floating rate

200

—

July 2024(2)

Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate

400

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, ~~2021~~2022 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, ~~2021~~2022 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, 2021~~18, 2022 and Note 10 ~~– Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated~~in “Item 1. Financial ~~Statements of Energy Transfer LP and Subsidiaries included~~Statements” 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 filed~~September 10, 2018, a ~~complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupture~~pipeline release and fire (the “Incident”) occurred on the ~~Noble to Douglas 8-inch~~Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries.

The PA AG commenced an ~~area~~investigation 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 immediately~~Pennsylvania issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.

On February 2, 2022, the PA AG issued a press release related to the Revolution pipeline, and ~~remediated~~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 ~~surrounding environment and pipeline in cooperation~~Clean 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 filed~~resolution also included terms that the ~~complaint alleging that SPLP failed to provide adequate cathodic protection~~company would pay a $22,500 fine to the ~~pipeline causing~~Clean Water Fund at the ~~failure. SPLP~~Pennsylvania 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 our~~There have been no material changes from the risk factors described in ~~"Part~~Part I, - Item ~~1A. Risk Factors"~~1A in the ~~Partnership's~~Partnership’s Annual Report on ~~Form 10-K~~Form10-K for the year ended December 31, ~~2020~~2021 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 Number						Description

~~2.1~~						Agreement and Plan of Merger, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC, solely for purposes of Section 2.1(a)(i) therein, LE GP, LLC, and, solely for purposes of Section 1.1(b)(i), CenterPoint Energy, Inc. (incorporated by reference to Exhibit 2.1 of Form 8-K (File No. 1-32740) filed February 16, 2021)
3.1						Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1 (File No. 333-128097) filed September 2, 2005)
3.2						Certificate of Amendment of Certificate of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed October 19, 2018)
3.3						Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed February 14, 2006)
3.4						Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K (File No. 1-32740) filed November 29, 2006)
3.5						Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K (File No. 1-32740) filed November 13, 2007)
3.6						Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed June 2, 2010)
3.7						Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed December 27, 2013)
3.8						Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated March 8, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed March 9, 2016)
3.9						Amendment No. 6 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated October 19, 2018 (incorporated by reference to Exhibit 3.9 of Form 10-Q (File No. 1-32740) filed November 8, 2018)

~~Table of Contents~~

~~Exhibit Number~~

~~Description~~

3.10

Amendment No. 7 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated August 6, 2019 (incorporated by reference to Exhibit 3.10 of Form 10-Q (File No. 1-32740) filed August 8, 2019)

3.11

Amendment No. 8 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated April 1, 2021 (incorporated by reference to Exhibit 2.2 of Form 8-K (File No. 1-32740) filed April 1, 2021)

3.12

Amendment No. 9 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated June 15, 2021 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed June 15, 2021)

22.1

Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 of Form 10-Q (File No. 1-32740) filed August 5, 2021)

31.1*

Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*

Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3*

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1**

Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2**

Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.3**

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

104

Cover 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, 2021~~3, 2022

By:

/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)~~


PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets			5

Consolidated Statements of Operations			7

Consolidated Statements of Comprehensive Income ~~(Loss)~~			8

Consolidated Statements of Equity			9

Consolidated Statements of Cash Flows			11

Notes to Consolidated Financial Statements			12



























ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			3839

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			63

ITEM 4. CONTROLS AND PROCEDURES			64

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS			65

ITEM 1A. RISK FACTORS			6566









ITEM 6. EXHIBITS			66

SIGNATURE			68


	September 30, 2021		December 31, 2020
Natural gas, NGLs and refined products(1)	$	1,238	$	1,013
Crude oil	160		287
Spare parts and other	413		439
Total inventories	$	1,811	$	1,739