UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

~~(Mark One)~~ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)


☒			~~QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)~~ OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, ~~2020~~2021


☐			~~TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)~~ ¨ 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 ~~30, 2020,~~29, 2021, the registrant had ~~2,697,716,489~~2,705,855,172 Common Units outstanding.

Table of Contents

FORM 10-Q

ENERGY TRANSFER LP AND SUBSIDIARIES

TABLE OF CONTENTS

Table of Contents

Definitions

References to the “Partnership” or “ET” 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



			~~Btu~~						~~British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content~~

































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

			~~DOJ~~Dakota Access						~~U.S. Department of Justice~~Dakota Access, LLC



			Enable						Enable Midstream Partners, LP, a Delaware limited partnership

			~~EPA~~Energy Transfer Canada						~~U.S. Environmental Protection Agency~~Energy Transfer Canada ULC, a less than wholly-owned subsidiary of ET

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



			ET 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, which owns the Tiger Pipeline






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





			~~ETO Series A Preferred Units~~						~~ETO’s 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units~~

			~~ETO Series B Preferred Units~~						~~ETO’s 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units~~

			~~ETO Series C Preferred Units~~						~~ETO’s 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units~~

			~~ETO Series D Preferred Units~~						~~ETO’s 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units~~

			~~ETO Series E Preferred Units~~						~~ETO’s 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units~~

			~~ETO Series F Preferred Units~~						~~ETO’s 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units~~

			~~ETO Series G Preferred Units~~						~~ETO’s 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units~~

			~~ETP GP~~						~~Energy Transfer Partners GP, L.P., the general partner of ETO~~

			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















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

			~~Lake Charles LNG~~						~~Lake Charles LNG Company, LLC, a wholly-owned subsidiary of ETO~~

			LE GP						LE GP, LLC, the general partner of ET

			LIBOR						London Interbank Offered Rate















			MBbls						thousand barrels

			MEP						Midcontinent Express Pipeline LLC

			MTBE						methyl tertiary butyl ether





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





			NYMEX						New York Mercantile Exchange

~~Table of Contents~~


			OSHA						Federal Occupational Safety and Health Act

			OTC						over-the-counter

			Panhandle						Panhandle Eastern Pipe Line Company, LP, ~~and its subsidiaries,~~a wholly-owned ~~by ETO~~subsidiary of ET









			~~PES~~						~~Philadelphia Energy Solutions Refining and Marketing LLC~~





















			Regency						Regency Energy Partners LP



			Rover						Rover Pipeline LLC

















			SEC						Securities and Exchange Commission

			~~SemCAMS~~Series A Preferred Units						~~SemCAMS Midstream ULC, a less than wholly-owned subsidiary of ETO~~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

			~~SemGroup~~Series C Preferred Units						~~SemGroup, LLC (formerly SemGroup Corporation)~~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



			~~Series A Convertible Preferred Units~~						~~ET Series A convertible preferred units~~













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

















			~~Sunoco R&M~~						~~Sunoco (R&M), LLC (formerly Sunoco, Inc. (R&M))~~



			Transwestern						Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ~~ETO~~ET

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



			USAC						USA Compression Partners, LP, a subsidiary of ~~ETO~~ET

			USAC Preferred Units						USAC Series A ~~Preferred Units~~preferred units

			White Cliffs						White Cliffs Pipeline, L.L.C.

~~iii~~4

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

September 30,
2020 December 31, 2019*
ASSETS
Current assets:
Cash and cash equivalents $ 275 $ 291
Accounts receivable, net 3,731 5,038
Accounts receivable from related companies 90 159
Inventories 1,723 1,532
Income taxes receivable 77 146
Derivative assets 19 23
Other current assets 235 275
Total current assets 6,150 7,464
Property, plant and equipment 93,239 89,790
Accumulated depreciation and depletion (18,111) (15,597)
75,128 74,193
Advances to and investments in unconsolidated affiliates 3,068 3,460
Lease right-of-use assets, net 934 964
Other non-current assets, net 1,582 1,571
Intangible assets, net 5,915 6,154
Goodwill 2,418 5,167
Total assets $ 95,195 $ 98,973

*As adjusted. See Note 1.

~~The accompanying notes are an integral part of these consolidated financial statements.~~

~~Table of Contents~~

~~ENERGY TRANSFER LP AND SUBSIDIARIES~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Dollars in million)~~

~~(unaudited)~~

September 30,
2020 December 31, 2019*
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 2,765 $ 4,118
Accounts payable to related companies 30 31
Derivative liabilities 264 147
Operating lease current liabilities 54 60
Accrued and other current liabilities 2,913 3,342
Current maturities of long-term debt 21 26
Total current liabilities 6,047 7,724
Long-term debt, less current maturities 51,424 51,028
Non-current derivative liabilities 275 273
Non-current operating lease liabilities 901 901
Deferred income taxes 3,349 3,208
Other non-current liabilities 1,152 1,162
Commitments and contingencies
Redeemable noncontrolling interests 756 739
Equity:
Limited Partners:
Common Unitholders 18,296 21,935
General Partner (8) (4)
Accumulated other comprehensive loss (4) (11)
Total partners’ capital 18,284 21,920
Noncontrolling interests 13,007 12,018
Total equity 31,291 33,938
Total liabilities and equity $ 95,195 $ 98,973

*As adjusted. See Note 1.

~~The accompanying notes are an integral part of these consolidated financial statements.~~

~~Table of Contents~~

~~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,
2020 2019* 2020 2019*
REVENUES:
Refined product sales $ 2,720 $ 4,311 $ 7,952 $ 12,514
Crude sales 2,298 3,971 7,170 11,842
NGL sales 1,808 1,723 4,751 6,121
Gathering, transportation and other fees 2,283 2,466 6,805 6,768
Natural gas sales 681 822 1,783 2,549
Other 165 202 459 699
Total revenues 9,955 13,495 28,920 40,493
COSTS AND EXPENSES:
Cost of products sold 6,376 9,864 18,784 29,642
Operating expenses 773 806 2,422 2,406
Depreciation, depletion and amortization 912 784 2,715 2,343
Selling, general and administrative 176 173 555 499
Impairment losses 1,474 12 2,803 62
Total costs and expenses 9,711 11,639 27,279 34,952
OPERATING INCOME 244 1,856 1,641 5,541
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized (569) (579) (1,750) (1,747)
Equity in earnings (losses) of unconsolidated affiliates (32) 82 46 224
Impairment of investment in an unconsolidated affiliate (129) 0 (129) 0
Losses on extinguishments of debt 0 0 (62) (18)
Gains (losses) on interest rate derivatives 55 (175) (277) (371)
Other, net 71 57 6 99
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (360) 1,241 (525) 3,728
Income tax expense 41 54 168 214
NET INCOME (LOSS) (401) 1,187 (693) 3,514
Less: Net income attributable to noncontrolling interests 369 317 554 931
Less: Net income attributable to redeemable noncontrolling interests 12 12 37 38
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS (782) 858 (1,284) 2,545
General Partner’s interest in net income (loss) 0 1 (1) 3
Limited Partners’ interest in net income (loss) $ (782) $ 857 $ (1,283) $ 2,542
NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
Basic $ (0.29) $ 0.33 $ (0.48) $ 0.97
Diluted $ (0.29) $ 0.33 $ (0.48) $ 0.97

*As adjusted. See Note 1.

~~The accompanying notes are an integral part of these consolidated financial statements.~~

~~Table of Contents~~

~~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,
2020 2019* 2020 2019*
Net income (loss) $ (401) $ 1,187 $ (693) $ 3,514
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities 3 0 3 8
Actuarial gain (loss) related to pension and other postretirement benefit plans 4 (3) 15 7
Foreign currency translation adjustments 18 0 (16) 0
Change in other comprehensive income (loss) from unconsolidated affiliates 1 (4) (15) (13)
26 (7) (13) 2
Comprehensive income (loss) (375) 1,180 (706) 3,516
Less: Comprehensive income attributable to noncontrolling interests 369 317 554 931
Less: Comprehensive income attributable to redeemable noncontrolling interests 12 12 37 38
Comprehensive income (loss) attributable to partners $ (756) $ 851 $ (1,297) $ 2,547

*As adjusted. See Note 1.

~~The accompanying notes are an integral part of these consolidated financial statements.~~

~~Table of Contents~~

~~ENERGY TRANSFER LP AND SUBSIDIARIES~~

~~CONSOLIDATED STATEMENTS OF EQUITY~~

~~FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2020 AND 2019~~

~~(Dollars in millions)~~

~~(unaudited)~~

Common 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) 0 0 (1,592)
Distributions to noncontrolling interests 0 0 0 (444) (444)
Subsidiary units issued 0 0 0 1,580 1,580
Capital contributions from noncontrolling interests 0 0 0 95 95
Other comprehensive loss, net of tax 0 0 (48) (38) (86)
Other, net 22 0 0 (7) 15
Net loss, excluding amounts attributable to redeemable noncontrolling interests (854) (1) 0 (121) (976)
Balance, March 31, 2020 19,512 (6) (59) 13,083 32,530
Distributions to partners 9 (1) 0 0 8
Distributions to noncontrolling interests 0 0 0 (408) (408)
Units issued 0 0 0 0 0
Capital contributions from noncontrolling interests 0 0 0 83 83
Other comprehensive income, net of tax 0 0 38 9 47
Other, net (31) 0 0 4 (27)
Net income, excluding amounts attributable to redeemable noncontrolling interests 353 0 0 306 659
Balance, June 30, 2020 19,843 (7) (21) 13,077 32,892
Distributions to partners (812) (1) 0 0 (813)
Distributions to noncontrolling interests 0 0 0 (430) (430)
Capital contributions from noncontrolling interests 0 0 0 25 25
Other comprehensive loss, net of tax 0 0 17 9 26
Other, net 47 0 0 (43) 4
Net income (loss), excluding amounts attributable to redeemable noncontrolling interests (782) 0 0 369 (413)
Balance, September 30, 2020 $ 18,296 $ (8) $ (4) $ 13,007 $ 31,291

*As adjusted. See Note 1.


	September 30, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	313	$	367
Accounts receivable, net	6,437		3,875
Accounts receivable from related companies	63		79
Inventories	1,811		1,739
Income taxes receivable	42		35
Derivative assets	57		9
Other current assets	326		213
Total current assets	9,049		6,317

Property, plant and equipment	95,775		94,115
Accumulated depreciation and depletion	(21,504)		(19,008)
	74,271		75,107

Investments in unconsolidated affiliates	2,958		3,060

Lease right-of-use assets, net	829		866


Other non-current assets, net	1,722		1,657
Intangible assets, net	5,474		5,746
Goodwill	2,395		2,391
Total assets	$	96,698	$	95,144

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

Common Unitholders General Partner AOCI Noncontrolling Interests Total
Balance, December 31, 2018* $ 20,773 $ (5) $ (42) $ 10,291 $ 31,017
Distributions to partners (799) (1) 0 0 (800)
Distributions to noncontrolling interests 0 0 0 (425) (425)
Capital contributions from noncontrolling interests 0 0 0 140 140
Sale of noncontrolling interest in subsidiary 0 0 0 93 93
Other comprehensive income, net of tax 0 0 8 0 8
Other, net 17 0 0 12 29
Net income, excluding amounts attributable to redeemable noncontrolling interests 807 1 0 297 1,105
Balance, March 31, 2019* 20,798 (5) (34) 10,408 31,167
Distributions to partners (748) (1) 0 0 (749)
Distributions to noncontrolling interests 0 0 0 (388) (388)
Subsidiary units issued 0 0 0 780 780
Capital contributions from noncontrolling interests 0 0 0 66 66
Other comprehensive income, net of tax 0 0 1 0 1
Other, net 50 0 0 0 50
Net income, excluding amounts attributable to redeemable noncontrolling interests 878 1 0 317 1,196
Balance, June 30, 2019* 20,978 (5) (33) 11,183 32,123
Distributions to partners (800) 0 0 0 (800)
Distributions to noncontrolling interests 0 0 0 (457) (457)
Units issued 49 0 0 0 49
Capital contributions from noncontrolling interests 0 0 0 72 72
Other comprehensive loss, net of tax 0 0 (7) 0 (7)
Other, net 10 0 0 9 19
Net income, excluding amounts attributable to redeemable noncontrolling interests 857 1 0 317 1,175
Balance, September 30, 2019* $ 21,094 $ (4) $ (40) $ 11,124 $ 32,174
ENERGY TRANSFER LP AND SUBSIDIARIES

*As adjusted. See Note 1.CONSOLIDATED BALANCE SHEETS (continued)

(Dollars in million)

(unaudited)


	September 30, 2021		December 31, 2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	5,707	$	2,809
Accounts payable to related companies	—		27
Derivative liabilities	205		238

Operating lease current liabilities	46		53
Accrued and other current liabilities	3,198		2,775
Current maturities of long-term debt	678		21
Total current liabilities	9,834		5,923

Long-term debt, less current maturities	44,793		51,417

Non-current derivative liabilities	187		237
Non-current operating lease liabilities	799		837
Deferred income taxes	3,683		3,428
Other non-current liabilities	1,270		1,152

Commitments and contingencies	0		0
Redeemable noncontrolling interests	783		762

Equity:
Limited Partners:
Preferred Unitholders	5,671		—
Common Unitholders	21,726		18,531
General Partner	(5)		(8)
Accumulated other comprehensive income	19		6
Total partners’ capital	27,411		18,529
Noncontrolling interests	7,938		12,859
Total equity	35,349		31,388
Total liabilities and equity	$	96,698	$	95,144

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~OPERATIONS

(Dollars in ~~millions)~~millions, except per unit data)

(unaudited)

Nine Months Ended
September 30,
2020 2019*
OPERATING ACTIVITIES:
Net income (loss) $ (693) $ 3,514
Reconciliation of net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 2,715 2,343
Deferred income taxes 159 191
Inventory valuation adjustments 126 (71)
Non-cash compensation expense 93 85
Impairment losses 2,803 62
Impairment of investment in an unconsolidated affiliate 129 0
Losses on extinguishments of debt 62 18
Distributions on unvested awards (33) (27)
Equity in earnings of unconsolidated affiliates (46) (224)
Distributions from unconsolidated affiliates 176 254
Other non-cash (130) 33
Net change in operating assets and liabilities, net of effects of acquisitions 94 (212)
Net cash provided by operating activities 5,455 5,966
INVESTING ACTIVITIES:
Cash proceeds from sale of noncontrolling interest in subsidiary 0 93
Cash paid for all other acquisitions, net of cash received 0 (7)
Capital expenditures, excluding allowance for equity funds used during construction (4,030) (4,181)
Contributions in aid of construction costs 61 63
Contributions to unconsolidated affiliates (37) (481)
Distributions from unconsolidated affiliates in excess of cumulative earnings 144 40
Proceeds from the sale of other assets 10 55
Other (9) (5)
Net cash used in investing activities (3,861) (4,423)
FINANCING ACTIVITIES:
Proceeds from borrowings 20,651 18,125
Repayments of debt (20,293) (17,247)
Subsidiary units issued for cash 1,580 780
Capital contributions from noncontrolling interests 203 278
Distributions to partners (2,397) (2,300)
Distributions to noncontrolling interests (1,282) (1,270)
Distributions to redeemable noncontrolling interest (37) 0
Debt issuance costs (53) (114)
Other, net 18 (3)
Net cash used in financing activities (1,610) (1,751)
Decrease in cash and cash equivalents (16) (208)
Cash and cash equivalents, beginning of period 291 419
Cash and cash equivalents, end of period $ 275 $ 211

*As adjusted. See Note 1.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
REVENUES:
Refined product sales	$	4,810	$	2,720	$	12,737	$	7,952
Crude sales	4,021		2,298		10,920		7,170
NGL sales	4,005		1,808		10,275		4,751
Gathering, transportation and other fees	2,276		2,283		6,797		6,805
Natural gas sales	1,376		681		7,507		1,783
Other	176		165		524		459
Total revenues	16,664		9,955		48,760		28,920
COSTS AND EXPENSES:
Cost of products sold	13,188		6,376		35,641		18,784
Operating expenses	898		773		2,585		2,422
Depreciation, depletion and amortization	943		912		2,837		2,715
Selling, general and administrative	198		176		583		555
Impairment losses	—		1,474		11		2,803
Total costs and expenses	15,227		9,711		41,657		27,279
OPERATING INCOME	1,437		244		7,103		1,641
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(558)		(569)		(1,713)		(1,750)
Equity in earnings (losses) of unconsolidated affiliates	71		(32)		191		46
Impairment of investment in an unconsolidated affiliate	—		(129)		—		(129)
Losses on extinguishments of debt	—		—		(8)		(62)
Gains (losses) on interest rate derivatives	1		55		72		(277)
Other, net	33		71		45		6
INCOME (LOSS) BEFORE INCOME TAX EXPENSE	984		(360)		5,690		(525)
Income tax expense	77		41		234		168
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) ATTRIBUTABLE TO PARTNERS	635		(655)		4,549		(1,157)
General Partner’s interest in net income (loss)	1		—		5		(1)
Preferred Unitholders’ interest in net income	99		—		185		—
Limited Partners’ interest in net income (loss)	$	535	$	(655)	$	4,359	$	(1,156)



NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
Basic	$	0.20	$	(0.24)	$	1.61	$	(0.43)
Diluted	$	0.20	$	(0.24)	$	1.60	$	(0.43)

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

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,
	2021		2020		2021		2020
Net income (loss)	$	907	$	(401)	$	5,456	$	(693)
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2		3		5		3
Actuarial gain related to pension and other postretirement benefit plans	1		4		6		15
Foreign currency translation adjustments	(21)		18		3		(16)
Change in other comprehensive income (loss) from unconsolidated affiliates	1		1		1		(15)
	(17)		26		15		(13)
Comprehensive income (loss)	890		(375)		5,471		(706)
Less: Comprehensive income attributable to noncontrolling interests	250		251		872		407
Less: Comprehensive income attributable to redeemable noncontrolling interests	12		12		37		37
Comprehensive income (loss) attributable to partners	$	628	$	(638)	$	4,562	$	(1,150)

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

(unaudited)


	Common Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total
Balance, December 31, 2020	$	18,531	$	—	$	(8)	$	6	$	12,859	$	31,388
Distributions to partners	(406)		—		—		—		—		(406)
Distributions to noncontrolling interests	—		—		—		—		(406)		(406)

Capital contributions from noncontrolling interests	—		—		—		—		20		20
Other comprehensive income, net of tax	—		—		—		2		6		8
Other, net	18		—		—		—		3		21
Net income, excluding amounts attributable to redeemable noncontrolling interests	3,285		—		3		—		341		3,629
Balance, March 31, 2021	21,428		—		(5)		8		12,823		34,254
Preferred units converted in Rollup Mergers	—		4,768		—		—		(4,768)		—
Distributions to partners	(403)		(88)		(1)		—		—		(492)
Distributions to noncontrolling interests	—		—		—		—		(354)		(354)
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	—		—		—		—		51		51

Other comprehensive loss, net of tax	—		—		—		(7)		(10)		(17)
Other, net	16		(2)		—		—		5		19
Net income, excluding amounts attributable to redeemable noncontrolling interests	535		99		1		—		260		895
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 EQUITY (continued)

(Dollars in millions)

(unaudited)


	Common 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
Distributions to partners	(812)		(1)		—		—		(813)
Distributions to noncontrolling interests	—		—		—		(430)		(430)

Capital contributions from noncontrolling interests	—		—		—		25		25
Other comprehensive income, net of tax	—		—		17		9		26
Other, net	47		—		—		(43)		4
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

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,
	2021		2020
OPERATING ACTIVITIES:
Net income (loss)	$	5,456	$	(693)
Reconciliation of net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	2,837		2,715
Deferred income taxes	199		159
Inventory valuation adjustments	(168)		126
Non-cash compensation expense	81		93
Impairment losses	11		2,803
Impairment of investment in an unconsolidated affiliate	—		129
Losses on extinguishments of debt	8		62
Distributions on unvested awards	(19)		(33)
Equity in earnings of unconsolidated affiliates	(191)		(46)
Distributions from unconsolidated affiliates	226		176
Other non-cash	13		(130)
Net change in operating assets and liabilities, net of effects of acquisitions	970		94
Net cash provided by operating activities	9,423		5,455
INVESTING ACTIVITIES:
Capital expenditures, excluding allowance for equity funds used during construction	(2,046)		(4,030)
Contributions in aid of construction costs	29		61
Contributions to unconsolidated affiliates	(4)		(37)
Distributions from unconsolidated affiliates in excess of cumulative earnings	76		144
Proceeds from sales of other assets	38		10
Other	—		(9)
Net cash used in investing activities	(1,907)		(3,861)
FINANCING ACTIVITIES:
Proceeds from borrowings	11,839		20,651
Repayments of debt	(17,836)		(20,293)
Preferred Units issued for cash	889		—
Subsidiary units issued for cash	—		1,580
Capital contributions from noncontrolling interests	114		203
Distributions to partners	(1,383)		(2,397)
Distributions to noncontrolling interests	(1,149)		(1,282)
Distributions to redeemable noncontrolling interest	(37)		(37)
Debt issuance costs	(3)		(53)
Other, net	(4)		18
Net cash used in financing activities	(7,570)		(1,610)
Decrease in cash and cash equivalents	(54)		(16)
Cash and cash equivalents, beginning of period	367		291
Cash and cash equivalents, end of period	$	313	$	275

The accompanying notes are an integral part of these consolidated financial statements.

Table of Contents

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”). ~~References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.~~

~~In December 2019, we completed the acquisition~~On April 1, 2021, ET, ETO and certain of ~~SemGroup.~~ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). In connection with the ~~transaction,~~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 ~~ET merged with and~~ETO, were converted into SemGroup, with SemGroup surviving the merger. During the first and second quarters of 2020, ET contributed SemGroup and its former subsidiaries to ETO through sale and contribution transactions (together, the “SemGroup Transaction”).

~~Substantially all of the Partnership’s cash flows are derived from distributions related to its investment~~an aggregate 675,625,000 newly created Class B Units representing limited partner interests in ETO, which derives its cash flows from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ET’s subsidiaries.

~~Our financial statements reflect the following reportable segments:~~

•~~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~~

•~~corporate and other, including the following:~~

•~~activities of the Parent Company; and~~

•~~certain operations and investments that are not separately reflected as reportable segments.~~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, ~~2019,~~2020, filed with the SEC on February ~~21, 2020.~~19, 2021. 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 ETthe Partnership presented herein include the results of operations ~~of:~~

•~~the Parent Company;~~

•of our controlled ~~subsidiary, ETO;~~subsidiaries, including Sunoco LP and

•~~ETP GP, the general partner of ETO, and Energy Transfer Partners, L.L.C., the general partner of ETP GP.~~ USAC.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is

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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.

Certain prior period amounts have ~~also~~ been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity.

~~Change in Accounting Policy~~

Effective January 1, 2020, the Partnership elected to change its accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. Under the revised accounting policy, certain amounts of crude oil that are not available for sale have been reclassified from inventory to non-current assets. These crude oil barrels, which are owned by the Partnership’s crude oil acquisition and marketing business, include pipeline linefill and tank bottoms and are not considered to be available for sale because the volumes must be maintained in order to continue normal operation of the related pipelines or tanks and because there is no expectation of liquidation or sale of these volumes in the near term.

Under the previous accounting policy, all crude oil barrels were recorded as inventory under the weighted average cost method. Under the revised accounting policy, barrels related to pipeline linefill and tank bottoms are accounted for as long-lived assets and reflected as non-current assets on the consolidated balance sheet. These crude oil barrels will be tested for impairment consistent with the Partnership’s existing accounting policy for impairments of long-lived assets. The Partnership’s management believes that the change in accounting policy is preferable as it more closely aligns the accounting policies across the consolidated entity, given that similar assets in the Partnership’s natural gas, NGLs and refined products businesses are accounted for as non-current assets. In addition, management believes that reflecting these crude oil barrels as non-current assets better represents the economic results of the Partnership’s crude oil acquisition and marketing business by reducing volatility resulting from market price adjustments to crude oil barrels that are not expected to be sold or liquidated in the near term.

The impact of this accounting policy change on the Partnership’s net income for the nine months ended September 30, 2020 was $265 million, or $0.10 per limited partner unit. As a result of this change in accounting policy, the Partnership’s consolidated balance sheets for prior periods have been retrospectively adjusted as follows:

December 31, 2019 December 31, 2018
As Originally Reported Effect of Change As Adjusted As Originally Reported Effect of Change As Adjusted
Inventories $ 1,935 $ (403) $ 1,532 $ 1,677 $ (305) $ 1,372
Total current assets 7,867 (403) 7,464 6,750 (305) 6,445
Other non-current assets, net 1,075 496 1,571 1,006 472 1,478
Total assets 98,880 93 98,973 88,246 167 88,413
Total partners’ capital 21,827 93 21,920 20,559 167 20,726

~~In addition, the Partnership’s consolidated statements of operations, comprehensive income and cash flows for prior periods have been retrospectively adjusted as follows:~~

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Year Ended December 31, Three Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2019
As originally reported:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold $ 39,727 $ 41,658 $ 9,890 $ 29,607
Operating income 7,277 5,348 1,830 5,576
Income from continuing operations before income tax expense (benefit) 5,094 3,634 1,215 3,763
Net income 4,899 3,365 1,161 3,549
Net income per limited partner unit 1.37 1.16 0.32 0.98
Comprehensive income 4,930 3,322 1,154 3,551
Comprehensive income attributable to partners 3,623 1,651 825 2,582
Consolidated Statements of Cash Flows
Net income 4,899 3,365 1,161 3,549
Net change in operating assets and liabilities (518) 289 27 (247)
Effect of change:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold 74 (55) (26) 35
Operating income (74) 55 26 (35)
Income from continuing operations before income tax expense (benefit) (74) 55 26 (35)
Net income (74) 55 26 (35)
Net income per limited partner unit (0.03) 0.04 0.01 (0.01)
Comprehensive income (74) 55 26 (35)
Comprehensive income attributable to partners (74) 55 26 (35)
Consolidated Statements of Cash Flows
Net income (74) 55 26 (35)
Net change in operating assets and liabilities 74 (55) (26) 35
As adjusted:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold 39,801 41,603 9,864 29,642
Operating income 7,203 5,403 1,856 5,541
Income from continuing operations before income tax expense (benefit) 5,020 3,689 1,241 3,728
Net income 4,825 3,420 1,187 3,514
Net income per limited partner unit 1.34 1.20 0.33 0.97
Comprehensive income 4,856 3,377 1,180 3,516
Comprehensive income attributable to partners 3,549 1,706 851 2,547
Consolidated Statements of Cash Flows
Net income 4,825 3,420 1,187 3,514
Net change in operating assets and liabilities (444) 234 1 (212)

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Use of Estimates

The unaudited consolidated financial statements have been prepared in conformity with GAAP, which ~~includes~~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.

~~Recent Accounting Pronouncements~~2.ACQUISITIONS AND RELATED TRANSACTIONS

~~Effective January 1, 2020,~~Pending Enable Acquisition

On February 16, 2021, the Partnership ~~adopted Accounting Standards Update (“ASU”) 2016-13 “Financial Instruments - Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments.” ASU 2016-13 requires an entity~~entered into a definitive merger agreement to ~~utilize a new impairment model known as~~acquire Enable. Under the ~~current expected credit loss (“CECL”) model to estimate its lifetime “expected credit loss” and record an allowance that, when deducted from the amortized cost basis~~terms of the ~~financial asset, presents the net amount expected to be collected on the financial asset. The CECL model is expected to result~~merger agreement, Enable’s common unitholders will receive 0.8595 of an ET common unit in more timely recognition of credit losses. The impact of adoption was immaterial to the Partnership. However, due in large part to the global economic impacts of COVID-19, the Partnership and its subsidiaries recorded an aggregate $16 million of current expected credit lossesexchange for ~~the nine months ended September 30, 2020.~~

~~Goodwill~~

During the first quarter of 2020, due to the impacts of the COVID-19 pandemic, the decline in commodity prices and the decreases in the Partnership’s market capitalization, we determined that interim impairment testing should be performed on certain reporting units. We performed the interim impairment tests consistent with our approach for annual impairment testing, including using similar models, inputs and assumptions. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $483 million related to our Arklatex and South Texas operations within the midstream segment, a goodwill impairment of $183 million related to our Lake Charles LNG regasification operations within the interstate transportation and storage segment due to contractually scheduled reductions in payments for the remainder of the contract term, and a goodwill impairment of $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline.each Enable common unit. In addition, ~~USAC recognized~~each outstanding Enable preferred unit will be exchanged for 0.0265 of a ~~goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations.~~

During the three months ended September 30, 2020, the Partnership performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result, the Partnership recognized a goodwill impairment of $1.28 billion related to our crude operations, a goodwill impairment of $132 million related to our SemCAMS operations within the all other segment and a goodwill impairment of $43 million related to our interstate operations primarily due to decreases in projected future cash flow as a result of the overall market demand decline. No other impairments of the Partnership’s goodwill were identified.

In connection with aforementioned impairments, the Partnership determined the fair value of our reporting units using the income approach. The income approach is based on the present value of future cash flows, which are derived from our long-term financial forecasts, and requires significant assumptions including, among others, revenue growth rates, operating margins, weighted average costs of capital and future market conditions. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Cash flow projections are derived from one-year budgeted amounts and three-year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur.

Series G Preferred

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~~Changes~~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.

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 ~~carrying amount~~fourth quarter of ~~goodwill were 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 All Other Total
Balance, December 31, 2019 $ 10 $ 226 $ 483 $ 693 $ 1,397 $ 1,555 $ 619 $ 184 $ 5,167
Impaired 0 (183) (483) 0 0 0 (619) (40) (1,325)
Other 0 0 0 0 0 0 0 (7) (7)
Balance, March 31, 2020 10 43 0 693 1,397 1,555 0 137 3,835
Other 0 0 0 0 0 0 0 33 33
Balance, June 30, 2020 10 43 0 693 1,397 1,555 0 170 3,868
Impaired 0 (43) 0 0 (1,279) 0 0 (132) (1,454)
Other 0 0 0 0 (66) 0 0 70 4
Balance, September 30, 2020 $ 10 $ 0 $ 0 $ 693 $ 52 $ 1,555 $ 0 $ 108 $ 2,418
2021.

2.3.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, ~~2020~~2021 or December 31, ~~2019.~~2020.

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~~net of effects of ~~acquisitions)~~acquisitions, included in cash flows from operating activities is comprised as follows:


		Nine Months Ended September 30,					Nine Months Ended September 30,
		2020		2019			2021		2020
Accounts receivable	Accounts receivable	$	1,307	$	(353)	Accounts receivable	$	(2,562)	$	1,307
Accounts receivable from related companies	Accounts receivable from related companies	(258)		(36)		Accounts receivable from related companies	16		(258)
Inventories	Inventories	(298)		(7)		Inventories	96		(298)
Other current assets	Other current assets	108		14		Other current assets	(127)		108
Other non-current assets, net	Other non-current assets, net	(26)		(151)		Other non-current assets, net	(57)		(26)
Accounts payable	Accounts payable	(1,354)		25		Accounts payable	2,917		(1,354)
Accounts payable to related companies	Accounts payable to related companies	370		(37)		Accounts payable to related companies	(31)		370
Accrued and other current liabilities	Accrued and other current liabilities	127		129		Accrued and other current liabilities	711		127
Other non-current liabilities	Other non-current liabilities	(5)		(103)		Other non-current liabilities	138		(5)
Derivative assets and liabilities, net	Derivative assets and liabilities, net	123		307		Derivative assets and liabilities, net	(131)		123
Net change in operating assets and liabilities, net of effects of acquisitions	Net change in operating assets and liabilities, net of effects of acquisitions	$	94	$	(212)	Net change in operating assets and liabilities, net of effects of acquisitions	$	970	$	94

Non-cash activities were as follows:


		Nine Months Ended September 30,					Nine Months Ended September 30,
		2020		2019			2021		2020
NON-CASH INVESTING AND FINANCING ACTIVITIES:	NON-CASH INVESTING AND FINANCING ACTIVITIES:					NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	Accrued capital expenditures	$	684	$	1,202	Accrued capital expenditures	$	385	$	684

Lease assets obtained in exchange for new lease liabilities	Lease assets obtained in exchange for new lease liabilities	130		73		Lease assets obtained in exchange for new lease liabilities	10		130
Distribution reinvestment	Distribution reinvestment	72		100		Distribution reinvestment	24		72

4.INVENTORIES

Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

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3.~~INVENTORIES~~

Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As ~~further discussed in Note 1,~~of September 30, 2021 and December 31, 2020, the ~~Partnership elected to change~~carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $143 million and $311 million, respectively, and the inventory carrying value equaled or exceeded its ~~accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. As a result of this change in accounting policy,~~replacement cost. For the three and nine months ended September 30, 2021 and 2020, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of 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 to changes in fuel prices, Sunoco LP recorded an inventory ~~balance~~adjustment on the value of its fuel inventory of $168 million for the ~~prior period has been retrospectively adjusted.~~

~~Inventories consisted of the following:~~

September 30,
2020 December 31,
2019
Natural gas, NGLs and refined products $ 914 $ 833
Crude oil 352 251
Spare parts and other 457 448
Total inventories $ 1,723 $ 1,532
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 sheets and cost of products sold in our consolidated statements of operations.

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, 2020 and December 31, 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $360 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost. For the three and nine months ended September 30, 2020 and 2019, the Partnership’s consolidated income statements did not include any material amounts of income from the liquidation of LIFO fuel inventory.

4.5.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 clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the nine months ended September 30, ~~2020, 0~~2021, 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, ~~2020~~2021 and December 31, ~~2019~~2020 based on inputs used to derive their fair values:


				Fair Value Measurements at September 30, 2020					Fair Value Measurements at September 30, 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	$	13	$	13	$	0	Basis Swaps IFERC/NYMEX	$	14	$	14	$	—
Swing Swaps IFERC	Swing Swaps IFERC	2		0		2		Swing Swaps IFERC	11		11		—
Fixed Swaps/Futures	Fixed Swaps/Futures	5		5		0		Fixed Swaps/Futures	4		4		—

Forward Physical Contracts	Forward Physical Contracts	6		0		6		Forward Physical Contracts	4		—		4
Power:	Power:							Power:
Forwards	Forwards	8		0		8		Forwards	36		—		36
Futures	Futures	2		2		0		Futures	4		4		—
Options – Puts		0		0		0

Options – Calls	Options – Calls	1		1		0		Options – Calls	1		1		—
NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	103		103		0		NGLs – Forwards/Swaps	384		384		—
Refined Products – Futures	Refined Products – Futures	5		5		0		Refined Products – Futures	7		7		—
Crude – Forwards/Swaps	Crude – Forwards/Swaps	2		2		0		Crude – Forwards/Swaps	569		569		—

Total commodity derivatives	Total commodity derivatives	147		131		16		Total commodity derivatives	1,034		994		40
Other non-current assets	Other non-current assets	31		20		11		Other non-current assets	37		24		13
Total assets	Total assets	$	178	$	151	$	27	Total assets	$	1,071	$	1,018	$	53
Liabilities:	Liabilities:							Liabilities:
Interest rate derivatives	Interest rate derivatives	$	(522)	$	0	$	(522)	Interest rate derivatives	$	(376)	$	—	$	(376)
Commodity derivatives:	Commodity derivatives:							Commodity derivatives:
Natural Gas:	Natural Gas:							Natural Gas:
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(9)		(9)		0		Basis Swaps IFERC/NYMEX	(5)		(5)		—
Swing Swaps IFERC	Swing Swaps IFERC	(4)		(1)		(3)		Swing Swaps IFERC	(7)		(7)		—
Fixed Swaps/Futures	Fixed Swaps/Futures	(29)		(29)		0		Fixed Swaps/Futures	(78)		(78)		—

Forward Physical Contracts								Forward Physical Contracts	(1)		—		(1)
Power:	Power:							Power:
Forwards	Forwards	(3)		0		(3)		Forwards	(21)		—		(21)
Futures	Futures	(2)		(2)		0		Futures	(11)		(11)		—

Options – Calls								Options – Calls	(2)		(2)		—

NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	(153)		(153)		0		NGLs – Forwards/Swaps	(364)		(364)		—
Refined Products – Futures	Refined Products – Futures	(4)		(4)		0		Refined Products – Futures	(10)		(10)		—

Crude – Forwards/Swaps								Crude – Forwards/Swaps	(582)		(582)		—
Total commodity derivatives	Total commodity derivatives	(204)		(198)		(6)		Total commodity derivatives	(1,081)		(1,059)		(22)
Total liabilities	Total liabilities	$	(726)	$	(198)	$	(528)	Total liabilities	$	(1,457)	$	(1,059)	$	(398)

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				Fair Value Measurements at December 31, 2019					Fair Value Measurements at December 31, 2020
		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	$	17	$	17	$	0	Basis Swaps IFERC/NYMEX	$	12	$	12	$	—
Swing Swaps IFERC	Swing Swaps IFERC	1		0		1		Swing Swaps IFERC	1		—		1
Fixed Swaps/Futures	Fixed Swaps/Futures	65		65		0		Fixed Swaps/Futures	13		13		—

Forward Physical Contracts	Forward Physical Contracts	3		0		3		Forward Physical Contracts	5		—		5
Power:	Power:							Power:
Forwards	Forwards	11		0		11		Forwards	4		—		4
Futures	Futures	4		4		0		Futures	2		2		—
Options – Puts		1		1		0

Options – Calls	Options – Calls	1		1		0		Options – Calls	1		1		—
NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	260		260		0		NGLs – Forwards/Swaps	127		127		—
Refined Products – Futures	Refined Products – Futures	8		8		0		Refined Products – Futures	3		3		—

Crude – Forwards/Swaps		13		13		0

Total commodity derivatives	Total commodity derivatives	384		369		15		Total commodity derivatives	168		158		10
Other non-current assets	Other non-current assets	31		20		11		Other non-current assets	34		22		12
Total assets	Total assets	$	415	$	389	$	26	Total assets	$	202	$	180	$	22
Liabilities:	Liabilities:							Liabilities:
Interest rate derivatives	Interest rate derivatives	$	(399)	$	0	$	(399)	Interest rate derivatives	$	(448)	$	—	$	(448)
Commodity derivatives:	Commodity derivatives:							Commodity derivatives:
Natural Gas:	Natural Gas:							Natural Gas:
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(49)		(49)		0		Basis Swaps IFERC/NYMEX	(11)		(11)		—
Swing Swaps IFERC	Swing Swaps IFERC	(1)		0		(1)		Swing Swaps IFERC	(3)		—		(3)
Fixed Swaps/Futures	Fixed Swaps/Futures	(43)		(43)		0		Fixed Swaps/Futures	(13)		(13)		—

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

Power:
Forwards		(5)		0		(5)
Futures	Futures	(3)		(3)		0		Futures	(3)		(3)		—

NGLs – Forwards/Swaps	NGLs – Forwards/Swaps	(278)		(278)		0		NGLs – Forwards/Swaps	(227)		(227)		—
Refined Products – Futures	Refined Products – Futures	(10)		(10)		0		Refined Products – Futures	(11)		(11)		—

Total commodity derivatives	Total commodity derivatives	(389)		(383)		(6)		Total commodity derivatives	(269)		(265)		(4)
Total liabilities	Total liabilities	$	(788)	$	(383)	$	(405)	Total liabilities	$	(717)	$	(265)	$	(452)

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, ~~2020~~2021 were ~~$52.28~~$51.26 billion and ~~$51.45~~$45.47 billion, respectively. As of December 31, ~~2019,~~2020, the aggregate fair value and carrying amount of our consolidated debt obligations were ~~$54.79~~$56.21 billion and ~~$51.05~~$51.44 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs ~~used~~ for similar liabilities.

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5.6.NET INCOME (LOSS) PER LIMITED PARTNER UNIT

A reconciliation of income or loss and weighted average units used in computing basic and diluted income (loss) per unit is as follows:

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019* 2020 2019*
Net income (loss) $ (401) $ 1,187 $ (693) $ 3,514
Less: Net income attributable to noncontrolling interests 369 317 554 931
Less: Net income attributable to redeemable noncontrolling interests 12 12 37 38
Net income (loss), net of noncontrolling interests (782) 858 (1,284) 2,545
Less: General Partner’s interest in income (loss) 0 1 (1) 3
Income (loss) available to Limited Partners $ (782) $ 857 $ (1,283) $ 2,542
Basic Income (Loss) per Limited Partner Unit:
Weighted average limited partner units 2,696.6 2,624.9 2,694.4 2,621.9
Basic income (loss) per Limited Partner unit $ (0.29) $ 0.33 $ (0.48) $ 0.97
Diluted Income (Loss) per Limited Partner Unit:
Income (loss) available to Limited Partners $ (782) $ 857 $ (1,283) $ 2,542
Dilutive effect of equity-based compensation of subsidiaries (1)
0 0 0 0
Diluted income (loss) available to Limited Partners $ (782) $ 857 $ (1,283) $ 2,542
Weighted average limited partner units 2,696.6 2,624.9 2,694.4 2,621.9
Dilutive effect of unvested unit awards (1)
0 10.6 0 11.0
Weighted average limited partner units, assuming dilutive effect of unvested unit awards 2,696.6 2,635.5 2,694.4 2,632.9
Diluted income (loss) from per Limited Partner unit $ (0.29) $ 0.33 $ (0.48) $ 0.97

*As adjusted. See Note 1.


	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)

(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.

6.7.DEBT OBLIGATIONS

~~Parent Company Indebtedness~~

~~ET Term Loan Facility~~

~~On January 15, 2019, ET paid in full all outstanding borrowings under its senior secured term loan agreement and thereafter terminated the term loan agreement.~~ In connection with the ~~termination~~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 ~~term loan agreement,~~respective indentures and credit agreements.

During the ~~collateral securing certain series~~first quarter of ~~the Partnership’s outstanding~~2021, ETO redeemed its $600 million aggregate principal amount of 4.40% senior notes ~~was released~~due April 1, 2021 and its $800 million aggregate principal amount of 4.65% senior notes due June 1, 2021, using proceeds from the Five-Year Credit Facility.

During the third quarter of 2021, ET issued par call notices to redeem in ~~accordance with the terms of the applicable indentures governing such senior notes.~~

~~Subsidiary Indebtedness~~

~~ETO January 2020 Senior Notes Offering and Redemption~~

~~On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00~~full its $1.0 billion aggregate principal amount of ~~ETO’s 2.900% Senior Notes~~5.2% senior notes due ~~2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030~~February 1, 2022, and $2.00 billion aggregate principal amount of ETO’s 5.000% Senior Notes due 2050 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by ETO’s wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis.

~~Using proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400~~$900 million aggregate principal amount of ~~5.75% Senior Notes~~5.875% senior notes due ~~September~~March 1, ~~2020,~~2022. The Partnership expects to redeem both series of senior notes during the fourth quarter of 2021, utilizing proceeds from its ~~$1.05 billion~~Five-Year Credit Facility.

On October 20, 2021, Sunoco LP completed a private offering of $800 million in aggregate principal amount of ~~4.15% Senior Notes~~4.500% senior notes due ~~October~~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, ~~2020,~~2021, ET assumed all of ETO’s obligations in respect of its ~~$1.14~~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 ~~aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250~~three-year term loan credit facility.

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~~million aggregate principal amount~~During the second quarter of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.

~~HFOTCO Long-Term Debt~~

~~In connection with~~2021, the contribution transactions discussed in Note 1, HFOTCO became a wholly-owned subsidiary of ETO in February 2020. As of September 30, 2020, HFOTCO had $225 million outstanding principal amount of tax exempt notes due 2050 (the “Ike Bonds”). The Ike Bonds are fully and unconditionally guaranteed by ETO,Partnership repaid $1.5 billion on ~~a senior unsecured basis. The indentures under which~~ the Ike Bonds were issued are subject to customary representations and warranties and affirmative and negative covenants, the majority of which are substantially similar to those found in ETO’s revolving credit facility, as further discussed below.

~~Credit Facilities and Commercial Paper~~

~~ETO~~ 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.

ETO’s term loan credit agreement provides for a $2 billion three-year term loan credit facility (the “ETO Term Loan”). Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The ETO Term Loan is unsecured and is guaranteed by ETO’s subsidiary, Sunoco Logistics Operations.

~~As of September 30, 2020, the ETO Term Loan had $2 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of September 30, 2020 was 1.15%.~~

~~ETO~~ 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 revolving credit facility (the ~~“ETO~~“Five-Year Credit Facility”) and Sunoco Logistics Operations was released as a guarantor in respect of the Five-Year Credit ~~Facility”)~~Facility. The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on December 1, ~~2023.~~2024. The ~~ETO~~ Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.

As of September 30, ~~2020,~~2021, the ~~ETO~~ Five-Year Credit Facility had ~~$3.23 billion~~$599 million of outstanding borrowings, ~~$1.63 billion~~ of which ~~was~~$590 million consisted of commercial paper. The amount available for future borrowings was ~~$1.65~~$4.37 billion, after ~~taking into account~~accounting for outstanding letters of credit in the amount of ~~$117~~$31 million. The weighted average interest rate on the total amount outstanding as of September 30, ~~2020~~2021 was ~~1.16%~~0.43%.

~~ETO~~ 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 ~~“ETO~~“364-Day Facility”) and Sunoco Logistics Operations was released as a guarantor in respect of the 364-Day ~~Facility”)~~Facility. The Partnership’s 364-Day Facility allows for unsecured borrowings up to $1.00 billion and matures on November ~~27, 2020.~~26, 2021. As of September 30, ~~2020,~~2021, the ~~ETO~~ 364-Day Facility had 0no outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion ~~senior secured~~ revolving credit facility (the “Sunoco LP Credit Facility”)~~, which matures in July 2023.~~. As of September 30, ~~2020,~~2021, the Sunoco LP Credit Facility had ~~$87~~$250 million of outstanding borrowings and $8$6 million in standby letters of ~~credit. As of~~credit and matures in July 2023. The amount available for future borrowings at September 30, ~~2020, Sunoco LP had $1.41 billion of availability under the Sunoco LP Credit Facility.~~2021 was $1.24 billion. The weighted average interest rate on the total amount outstanding as of September 30, ~~2020~~2021 was ~~2.15%~~2.09%.

USAC Credit Facility

USAC maintains a $1.60 billion ~~senior secured~~ revolving credit facility (the “USAC Credit Facility”), ~~with a further potential increase of~~which matures on April 2, 2023 and permits up to $400 million ~~which matures~~of future increases in ~~April 2023.~~borrowing capacity. As of September 30, ~~2020, the~~2021, USAC ~~Credit Facility~~ had ~~$497~~$506 million of outstanding borrowings ~~and 0 outstanding letters of credit.~~under the USAC Credit Facility. As of September 30, ~~2020,~~2021, USAC had ~~$1.10~~$1.09 billion of ~~borrowing base~~ availability under its credit facility, and subject to compliance with ~~the~~ applicable financial covenants, available borrowing capacity of ~~$412 million under the USAC Credit Facility.~~$114 million. The weighted average interest rate on the total amount outstanding as of September 30, ~~2020~~2021 was ~~3.03%~~2.96%.

~~SemCAMS~~Energy Transfer Canada Credit Facilities

~~SemCAMS~~Energy Transfer Canada is party to a credit agreement providing for a C$350 million (US$~~262~~276 million at the September 30, ~~2020~~2021 exchange rate) senior secured term loan facility (the “Energy Transfer Canada Term Loan A”), a C$525 million (US$~~394~~414 million at the September 30, ~~2020~~2021 exchange rate) senior secured revolving credit facility (the “Energy Transfer Canada Revolving Credit Facility”), and a C$300 million (US$~~225~~237 million at theSeptember 30, ~~2020~~2021 exchange

~~Table of Contents~~

rate) senior secured construction loan facility (the “KAPS Facility”). The ~~term loan facility~~Energy Transfer Canada Term Loan A and the ~~revolving credit facility~~Energy Transfer Canada Revolving Credit Facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. ~~SemCAMS~~Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$~~187~~197 million at the September 30, ~~2020~~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, ~~2020,~~2021, the ~~SemCAMS senior secured term loan facility~~Energy Transfer Canada Term Loan A and ~~senior secured revolving credit facility~~the Energy Transfer Canada Revolving Credit Facility had ~~$253~~outstanding borrowings of C$320 million and ~~$74~~C$103 million, respectively ~~of outstanding borrowings.~~(US$252 million and US$81 million, respectively, at the September 30, 2021 exchange rate). As of September 30, ~~2020,~~2021, the KAPS Facility had outstanding borrowings of C$65 million (US$51 million at the 0 ~~outstanding borrowings.~~September 30, 2021 exchange rate).

Compliance with ~~Our~~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, ~~2020.~~2021. For the quarter ended September 30, ~~2020,~~2021, our leverage ratio, as calculated pursuant to the covenant related to our revolving credit facility, was ~~4.24x. On October 26, 2020, we announced a cash distribution for the third quarter~~3.15x.

Table of $0.1525 per unit ($0.61annualized) on ET common units. This distribution represents a 50% decrease as compared to the distribution for the prior quarter. The Partnership intends to use the excess cash flow resulting from this distribution decrease to reduce its level of indebtedness.Contents

7.8.REDEEMABLE NONCONTROLLING INTERESTS

Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of September 30, ~~2020~~2021 included a balance of $477 million related to the USAC Preferred Units described below and a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the ~~Partnership, and~~Partnership. In addition, as of September 30, 2021, redeemable noncontrolling interests included a balance of ~~$264~~$291 million related to ~~the SemCAMS~~Energy Transfer Canada preferred ~~stock described below.~~shares.

USAC Preferred Units

As of September 30, ~~2020,~~2021, USAC had 500,000 USAC Preferred Units issued and outstanding. The ~~holders of these units~~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 ~~will be~~are convertible into USAC common units at the election of the ~~holders beginning in 2021.~~holders. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by April 2, 2023, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, ~~at any time on or after~~beginning April 2, 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 ~~the Partnership~~USAC may elect to pay up to 50% of such redemption amount in USAC common units.

~~SemCAMS~~Energy Transfer Canada Redeemable Preferred Stock

~~As of September 30, 2020, SemCAMS had 337,046~~Energy Transfer Canada has 300,000 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at ~~SemCAMS’s~~Energy Transfer Canada’s option ~~subsequent to January 3, 2021~~ at a redemption price of C$1,100 (US$~~825~~867 at the September 30, ~~2020~~2021 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of ~~SemCAMS.~~Energy Transfer Canada. The preferred stock is convertible to ~~SemCAMS~~Energy Transfer Canada common shares in the event of an initial public offering by ~~SemCAMS.~~ Energy Transfer Canada.

Dividends on the preferred stock ~~may~~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-kind through June 30,~~in the fourth quarter of 2021.

8.9.EQUITY

ET Common Units

The change in ET ~~Common Units~~common units during the nine months ended September 30, ~~2020~~2021 was as follows:


			~~Nine Months Ended September 30, 2020~~Number of Units
Number of ~~Common Units, beginning of period~~common units at December 31, 2020			~~2,689.6~~2,702.4
Common ~~Units~~units issued in connection with the distribution reinvestment plan			~~6.9~~2.7

Common ~~Units~~units vested under equity incentive plans and other			~~1.2~~0.7
Number of ~~Common Units, end of period~~common units at September 30, 2021			~~2,697.7~~2,705.8

~~Table of Contents~~

ET Repurchase Program

During the nine months ended September 30, ~~2020,~~2021, ET did not repurchase any ET common units under its current buyback program. As of September 30, ~~2020,~~2021, $911 million remained available to repurchase under the current program.

ET Distribution Reinvestment Program

During the nine months ended September 30, ~~2020,~~2021, distributions of ~~$72~~$24 million were reinvested under the distribution reinvestment program. As of September 30, ~~2020,~~2021, a total of 2218 million ET common units ~~remain~~remained available to be issued under the existing registration statement in connection with the distribution reinvestment program.

~~Subsidiary Equity~~

Table of Contents

~~ETO Preferred Units~~

~~As of September 30, 2020 and December 31, 2019, ETO’s outstanding preferred units included 950,000 ETO Series A Preferred Units, 550,000ETO~~Series B Preferred Units, 18,000,000 ETO Series C Preferred Units, 17,800,000 ETO Series D Preferred Units and 32,000,000 ETO Series E Preferred Units. As of September 30, 2020, ETO’s outstanding preferred units also included 500,000 ETO Series F Preferred Units and 1,100,000 ETO Series G Preferred Units.

~~Sunoco LP Equity Distribution Program~~

For the nine months ended September 30, 2020, Sunoco LP issued 0 additional units under its at-the-market equity distribution program. As of September 30, 2020, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

~~USAC Distribution Reinvestment Program~~

During the nine months ended September 30, 2020, distributions of $1.4 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 140,318 USAC common units.

~~Parent Company~~ Cash Distributions on ET Common Units

Distributions declared and/or paid with respect to ET common units subsequent to December 31, ~~2019~~2020 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2019~~2020

February ~~7, 2020~~8, 2021

February 19, ~~2020~~2021

~~0.3050~~0.1525

March 31, ~~2020~~2021

May ~~7, 2020~~11, 2021

May 19, ~~2020~~2021

~~0.3050~~0.1525

June 30, ~~2020~~2021

August ~~7, 2020~~6, 2021

August 19, ~~2020~~2021

~~0.3050~~0.1525

September 30, ~~2020~~2021

November ~~6, 2020~~5, 2021

November 19, ~~2020~~2021

0.1525

The ~~Parent Company’s~~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 ~~reflects~~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 ~~reflects~~reflected only the reinvestment of distributions paid in May 2020.

ET Preferred Units

Conversion of ETO Preferred Units to ET Preferred Units

In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1, all of ETO’s previously outstanding preferred units were converted to ET 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.

As of September 30, 2021, ET’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,100,000 Series G Preferred Units and 900,000 Series H Preferred Units.

The following table summarizes changes in the ET Preferred Units:


	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

Cash Distributions on ET Preferred Units

Distributions declared on the ET Preferred Units were as follows:

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~~ETO Cash Distributions~~

~~Distributions declared and/or paid by ETO to its preferred unitholders subsequent to December 31, 2019 were as follows:~~

Period Ended Record Date Payment Date
Series A (1)
Series B (1)
Series C Series D Series E
Series F (2)
Series G (2)
December 31, 2019 February 3, 2020 February 18, 2020 $ 31.25 $ 33.125 $ 0.4609 $ 0.4766 $ 0.4750 $ 0 $ 0
March 31, 2020 May 1, 2020 May 15, 2020 0 0 0.4609 0.4766 0.4750 21.19 22.36
June 30, 2020 August 3, 2020 August 17, 2020 31.25 33.125 0.4609 0.4766 0.4750 0 0
September 30, 2020 November 2, 2020 November 16, 2020 0 0 0.4609 0.4766 0.4750 33.75 35.625


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)

(1)~~ETO~~Series A, ~~Preferred Unit and ETO~~ Series B, ~~Preferred Unit~~Series F, Series G and Series H distributions are paid on a semi-annual basis.

(2)Represents initial prorated distribution.

Description of ET Preferred Units

Following is a summary of the distribution and redemption rights associated with the ET Preferred Units:

•Series A Preferred Units. Distributions on 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.

~~(2)~~ •~~ETO~~ 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 ~~related~~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 ~~ended March 31, 2020 represent~~prior to, and including, each distribution reset date at a ~~prorated initial distribution. Distributions~~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

The Partnership’s consolidated financial statements include Sunoco LP and USAC, both of which are ~~paid~~publicly traded master limited partnerships, as well as other less-than-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 ~~a semi-annual basis.~~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 units declared and/or paid by Sunoco LP ~~to its common unitholders~~ subsequent to December 31, ~~2019~~2020 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2019~~2020

February ~~7, 2020~~8, 2021

February 19, ~~2020~~2021

0.8255

March 31, ~~2020~~2021

May ~~7, 2020~~11, 2021

May 19, ~~2020~~2021

0.8255

June 30, ~~2020~~2021

August ~~7, 2020~~6, 2021

August 19, ~~2020~~2021

0.8255

September 30, ~~2020~~2021

November ~~6, 2020~~5, 2021

November 19, ~~2020~~2021

0.8255

USAC Cash Distributions

Distributions on USAC’s units declared and/or paid by USAC ~~to its common unitholders~~ subsequent to December 31, ~~2019~~2020 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2019~~2020

January ~~27, 2020~~25, 2021

February ~~7, 2020~~5, 2021

~~0.5250~~0.525

March 31, ~~2020~~2021

April ~~27, 2020~~26, 2021

May ~~8, 2020~~7, 2021

~~0.5250~~0.525

June 30, ~~2020~~2021

July ~~31, 2020~~26, 2021

August ~~10, 2020~~6, 2021

~~0.5250~~0.525

September 30, ~~2020~~2021

October ~~26, 2020~~25, 2021

November ~~6, 2020~~5, 2021

~~0.5250~~0.525

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Accumulated Other Comprehensive Income (Loss)

The following table presents the components of AOCI, net of tax:

September 30,
2020 December 31,
2019
Available-for-sale securities $ 16 $ 13
Foreign currency translation adjustment (14) 2
Actuarial loss related to pensions and other postretirement benefits (10) (25)
Investments in unconsolidated affiliates, net (16) (1)
Total AOCI, net of tax (24) (11)
Amounts attributable to noncontrolling interest 20 0
Total AOCI included in partners’ capital, net of tax $ (4) $ (11)

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9.~~INCOME TAXES~~

The Partnership’s effective tax rate differs from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level.


	September 30, 2021		December 31, 2020
Available-for-sale securities	$	23	$	18
Foreign currency translation adjustment	12		7
Actuarial loss related to pensions and other postretirement benefits	(1)		(7)
Investments in unconsolidated affiliates, net	(13)		(14)

Total AOCI, net of tax	21		4
Amounts attributable to noncontrolling interest	(2)		2
Total AOCI included in partners’ capital, net of tax	$	19	$	6

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

By the 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”) to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the ~~Natural Gas Act.~~NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the ~~Order dated~~Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. AnThe 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.

In May 2021, the FERC commenced an audit of Sunoco Pipeline LP (“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 ~~expected in early 2021.~~ongoing.

Commitments

In the normal course of business, ~~ETO purchases, processes~~our subsidiaries purchase, process and ~~sells~~sell natural gas pursuant to long-term contracts and ~~enters~~enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ~~ETO believes~~We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on ~~its~~the Partnership’s financial position or results of operations.

~~ETO’s~~Our joint venture agreements require that ~~ETO~~we fund ~~its~~our proportionate share of capital contributions to ~~its~~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,
2020 2019 2020 2019
ROW expense $ 13 $ 5 $ 32 $ 17

~~PES Refinery Fire and Bankruptcy~~

We previously owned an approximately 7.4% indirect non-operating interest in PES, which owned a former refinery in Philadelphia. In addition, the Partnership previously provided logistics services to PES under commercial contracts and Sunoco LP previously purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.

On July 21, 2019, PES Holdings, LLC and seven of its subsidiaries (collectively, the “Debtors”) filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. In June 2020, the Partnership received $12 million from PES on the note payable and recorded a reserve for the remaining $63 million note balance.

In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of September 30, 2020, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such costs, and these liabilities are included in the total environmental liabilities discussed below under “Environmental Remediation.” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future depending upon the use of such property by the buyer; however, management is not currently able to estimate such additional liabilities.

PES has rejected certain of the Partnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward.

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
ROW expense	$	18	$	13	$	33	$	32

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 gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As 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 and December 31, 2020, accruals of approximately $130 million and $101 million, respectively, were reflected on our consolidated balance sheets related to contingencies 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 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.

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”) ~~permitting~~that allowed Dakota Access ~~LLC (“Dakota Access”)~~ to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE ~~allowing~~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 ~~court~~District Court remanded the case back to the USACE for preparation of an Environment Impact ~~Statement.~~Statement (“EIS”). On July 6, 2020, the ~~court~~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. The Court of Appeals also~~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 ~~will~~would be required to prepare an ~~Environmental Impact Statement. In addition, the Court of Appeals~~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 ~~expects~~expected the USACE to clarify its

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position with respect to whether USACE ~~intends~~intended to allow the continued operation of the pipeline notwithstanding the ~~vacator~~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~~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 ~~considers~~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. ~~Following the filing of this status report, the District Court ordered briefing on whether~~The Tribes subsequently filed a motion seeking an injunction to ~~enjoin~~stop the operation of the pipeline ~~with briefing scheduled to conclude by December 18, 2020.~~

~~Briefing on the merits~~and both of the ~~appeal to~~USACE and Dakota Access filed briefs in opposition of the motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.

On January 26, 2021, the Court of Appeals ~~has been completed,~~affirmed the District Court’s March 25, 2020 order requiring an EIS and ~~oral argument has been scheduled by~~its July 6, 2020 order vacating the easement. In this same January 26 order, the Court of Appeals ~~to occur~~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 ~~November 4, 2020. As a result of the ruling by~~April 12, 2021, which the Court of Appeals ~~related~~denied. Dakota Access filed a petition with the U.S. Supreme Court 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 ~~motions to stay and~~Motion. On May 3, 2021, USACE advised the District ~~Court’s briefing schedule related~~Court that it had not changed its position with respect to its opposition to the ~~injunction issue,~~Tribes’ motion for injunction. The USACE also advised the District Court that it is expected that the EIS will be completed by March 2022. On May 21, 2021 the District Court denied the Plaintiffs’ request for an injunction. The District Court further directed the parties to file a joint status report by June 11, 2021 concerning potential next steps in the litigation.

On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. 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 ~~will continue~~continues to operate ~~during the pendency~~pending completion of the ~~appeals process with~~EIS. The USACE now estimates that the ~~Court~~EIS will be complete by the end of ~~Appeals.~~

2022. ET cannot determine when or how ~~these~~future lawsuits will be resolved or the impact they may have on the Dakota Access pipelines; however, ET expects after the law and complete record are fully considered, ~~the issues in this litigation~~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 (“Lone Star”), now known as Energy Transfer GC NGLs LLC, facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations ~~have~~ resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage ~~wells; however,~~wells at the North Terminal that has not been returned to service. Lone Star ~~is still quantifying the extent of its incurred and ongoing damages and~~ has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star continues to quantify and ~~will continue to~~ seek reimbursement for ~~these~~outstanding losses.

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MTBE Litigation

ETC Sunoco Holdings LLC and ~~Sunoco (R&M), LLC~~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, ~~2020,~~2021, Sunoco Defendants are defendants in 5 cases, including one case each initiated by the States 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”).

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 Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP LP, Regency GP LLC, ET, ETO, ~~ETP~~Energy Transfer Partners GP, L.P., and the members of Regency’s board of directors.

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~~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 ~~the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of~~ this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit andappeal but intend to vigorously ~~defend against~~oppose it.

Litigation Filed By or Against Williams

In April and May 2016, the Williams Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against ET, LE GP, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, ~~“Defendants”~~“ET Defendants”), alleging that ET Defendants breached their obligations under the ET-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that ET 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~~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 ET Defendants and issued a declaratory judgment that ET 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 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 based on the alleged breaches of the Merger Agreement listed above. ET 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

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information to ET 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.

~~In July 2020,~~Trial was held regarding the ~~Court denied Defendant’s Motion for Summary Judgment~~parties’ amended claims on May 10-17, 2021, and ~~Williams’ Motion for Partial Summary Judgment. Trial is set for December 14-18, 2020.~~a post-trial hearing was held on September 16, 2021. ET Defendants cannot predict the outcome of the Williams Litigation ~~or any lawsuits that might be filed subsequent to~~nor can the ~~date of this filing; nor can~~ET Defendants predict the amount of time and expense that will be required to resolve ~~these lawsuits.~~the Williams Litigation. ET Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

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Rover

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and 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.~~concluded and oral argument was held on January 26, 2021. The ~~Ohio Supreme Court has not yet scheduled oral argument.~~parties are awaiting a decision.

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. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the PADEP in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a $28.6 million civil penalty and fund a $2 million community environmental project, and all related appeals were withdrawn.

The Pennsylvania Office of Attorney General has 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. The scope of these investigations is not further known at this time.

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 ~~former~~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. ~~To date, the Partnership is not aware of any further action with regard to this Notice.~~

In December 2019, the ~~former~~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 entered by the Court.

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”), 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 ~~Pennsylvania Attorney General Office~~AG served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. ~~While~~The Partnership has complied with the subpoena. On October 5, 2021, the AG held a press conference related to the Mariner East pipelines, released a Grand Jury Presentment and subsequently filed a criminal complaint against ET 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. The Partnership will ~~cooperate with~~defend itself vigorously against these charges. On October 13, 2021, the ~~subpoena, it intends to vigorously defend itself.~~AG announced that he is running for Governor of Pennsylvania.

~~Recently Filed~~Shareholder Litigation ~~Involving Energy Transfer LP~~Regarding Pennsylvania Pipeline Construction

Four purported unitholders of ET filed derivative actions against various past and current members of ET’s Board of Directors, LE GP, and ET, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment,

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waste of corporate assets, breach of ET’s limited partnership agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania. They also seek damages and changes to ET’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.).

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Another purported unitholder of ET, 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 ET and three of ET’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 ET 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. ~~The Court has not yet ruled on~~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. 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.

~~Other Litigation~~Cline Class Action

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco (R&M), LLC (now known as Energy Transfer R&M) and ~~Contingencies~~SPMT that alleged SPMT 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.

~~We or our subsidiaries are~~After a ~~party~~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 ~~various legal proceedings and/or regulatory proceedings incidental~~$80.7 million to ~~our businesses. For each~~account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of ~~these matters, we evaluate~~$75 million. The Class is also seeking attorneys’ fees.

On August 27, 2020, SPMT filed its Notice of Appeal with the ~~merits~~10th Circuit and appealed the entirety of the Order. The matter has now been fully briefed, and oral argument has been set for November 15, 2021. SPMT cannot predict the outcome of the case, ~~our exposure~~nor can SPMT predict the amount of time and expense that will be required to resolve the ~~matter, possible legal or settlement strategies,~~appeal, but intends to vigorously appeal the ~~likelihood~~entirety of ~~an unfavorable outcome and~~ the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2020 and December 31, 2019, accruals of approximately $86 million and $120 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.

In addition, other legal proceedings exist that are considered reasonably possible to result in unfavorable outcomes. For those where possible losses can be estimated, the range of possible losses related to these contingent obligations is estimated to be up to $80 million; however, no accruals have been recorded as of September 30, 2020 or December 31, 2019.Order.

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

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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.

~~In February 2017, we received letters from the DOJ on behalf~~

Table of EPA and Louisiana Department of Environmental Quality (“LDEQ”) notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with the DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees related to the Caddo Parish, Louisiana release.Contents

In October 2018, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly-owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. SPMT is currently awaiting response from PHMSA regarding the approval status of the submitted Remedial Work Plan.

On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The release occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty. The OCC has accepted our counter offer in conjunction with a proposed consent order. The Consent Order will be presented to the OCC at a final hearing, the date of which is to be determined.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

•~~Certain~~certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.

•~~Certain~~certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

•~~Legacy~~legacy sites related to Sunoco, ~~that~~Inc. are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that ~~Sunoco~~the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.

•~~Sunoco~~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, ~~2020, Sunoco~~2021, the Partnership had been named as a PRP at approximately 3133 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. ~~Sunoco~~The Partnership is usually one of a number of companies identified as a PRP at a site. ~~Sunoco~~The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon ~~Sunoco’s~~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

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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, 2020		December 31, 2019			September 30, 2021		December 31, 2020
Current	Current	$	46	$	46	Current	$	44	$	44
Non-current	Non-current	252		274		Non-current	253		262
Total environmental liabilities	Total environmental liabilities	$	298	$	320	Total environmental liabilities	$	297	$	306

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 ~~three months ended September 30, 2020 and 2019, the Partnership recorded $7 million and $16 million, respectively, of expenditures related to environmental cleanup programs. During the~~ nine months ended September 30, ~~2020~~2021 and ~~2019,~~2020, the Partnership recorded ~~$22~~$18 million and ~~$31~~$22 million, respectively, of expenditures related to environmental cleanup programs.

Our pipeline operations are subject to regulation by the United States Department of Transportation 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, 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 1413 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.

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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, ~~for a right to use our assets,~~ but allow customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

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


	Contract Liabilities
Balance, December 31, 2020	$	308
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

~~Balance, December 31, 2018~~	$	~~394~~
~~Additions~~	~~448~~
~~Revenue recognized~~	~~(491)~~
~~Balance, September 30, 2019~~	$	~~351~~

The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for expected credit losses. The allowance for expected credit losses represents Sunoco LP's best estimate of the probable losses associated with potential customer defaults. Sunoco LP estimates the expected credit losses based on historical write-off experience by industry and current expectations of future credit losses.

The balances of Sunoco LP’s contract assets ~~as of September 30, 2020 and December 31, 2019~~ were as follows:


		September 30, 2020		December 31, 2019			September 30, 2021		December 31, 2020
Contract balances:	Contract balances:					Contract balances:
Contract assets	Contract assets	$	123	$	117	Contract assets	$	148	$	121
Accounts receivable from contracts with customers	Accounts receivable from contracts with customers	225		366		Accounts receivable from contracts with customers	473		256

~~Costs to Obtain or Fulfill a Contract~~

Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g., sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in the future, and are expected to be recovered. These capitalized costs are recorded as a part

Table of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the three months ended September 30, 2020 and 2019 was $4 million and $4 million, respectively. The amount of amortization expense that Sunoco LP recognized for the nine months ended September 30, 2020 and 2019 was $14 million and $12 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.Contents

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

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distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total ~~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 of the contracts are included in the table below.

As of September 30, ~~2020,~~2021, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations ~~is $39.50~~was $40.13 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:

Years Ending December 31,
2020 (remainder) 2021 2022 Thereafter Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2020 $ 1,633 $ 5,674 $ 5,180 $ 27,016 $ 39,503


	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

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, 2020		December 31, 2019			September 30, 2021		December 31, 2020
		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):
Basis Swaps IFERC/NYMEX (1)	Basis Swaps IFERC/NYMEX (1)	(91,365)	2020-2021	(35,208)	2020-2024	Basis Swaps IFERC/NYMEX (1)	(81,963)	2021-2022	(44,225)	2021-2022
Fixed Swaps/Futures	Fixed Swaps/Futures	4,965	2020-2022	1,483	2020	Fixed Swaps/Futures	475	2021-2023	1,603	2021-2022

Power (Megawatt):	Power (Megawatt):					Power (Megawatt):
Forwards	Forwards	1,714,800	2020-2029	3,213,450	2020-2029	Forwards	712,400	2021-2029	1,392,400	2021-2029
Futures	Futures	(35,313)	2020-2022	(353,527)	2020	Futures	(640,800)	2021-2022	18,706	2021-2022
Options – Puts	Options – Puts	(15)	2020-2021	51,615	2020	Options – Puts	290,400	2021-2022	519,071	2021
Options – Calls	Options – Calls	(6,323,560)	2020-2022	(2,704,330)	2020-2021	Options – Calls	36,704	2021-2022	2,343,293	2021

(Non-Trading)	(Non-Trading)					(Non-Trading)
Natural Gas (BBtu):	Natural Gas (BBtu):					Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(20,800)	2020-2022	(18,923)	2020-2022	Basis Swaps IFERC/NYMEX	(8,893)	2021-2022	(29,173)	2021-2022
Swing Swaps IFERC	Swing Swaps IFERC	(7,480)	2020-2021	(9,265)	2020	Swing Swaps IFERC	(48,675)	2021-2022	11,208	2021
Fixed Swaps/Futures	Fixed Swaps/Futures	(43,708)	2020-2022	(3,085)	2020-2021	Fixed Swaps/Futures	(45,588)	2021-2023	(53,575)	2021-2022
Forward Physical Contracts	Forward Physical Contracts	(15,281)	2021	(13,364)	2020-2021	Forward Physical Contracts	(10,071)	2021	(11,861)	2021

NGLs (MBbls) – Forwards/Swaps	NGLs (MBbls) – Forwards/Swaps	(14,743)	2020-2022	(1,300)	2020-2021	NGLs (MBbls) – Forwards/Swaps	2,785	2021-2023	(5,840)	2021-2022
Refined Products (MBbls) – Futures	Refined Products (MBbls) – Futures	(3,391)	2020-2022	(2,473)	2020-2021	Refined Products (MBbls) – Futures	(3,272)	2021-2023	(2,765)	2021
Crude (MBbls) – Forwards/Swaps	Crude (MBbls) – Forwards/Swaps	1,929	2020	4,465	2020	Crude (MBbls) – Forwards/Swaps	1,693	2021-2022	—	—
Corn (thousand bushels)		0	—	(1,210)	2020

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	(38,490)	2020-2021	(31,780)	2020	Basis Swaps IFERC/NYMEX	(21,255)	2021	(30,113)	2021
Fixed Swaps/Futures	Fixed Swaps/Futures	(38,490)	2020-2021	(31,780)	2020	Fixed Swaps/Futures	(21,255)	2021	(30,113)	2021
Hedged Item – Inventory	Hedged Item – Inventory	38,490	2020-2021	31,780	2020	Hedged Item – Inventory	21,255	2021	30,113	2021

(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
September 30,
2020 December 31,
2019
July 2020(2)(3)
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $ 0 $ 400
July 2021(2)
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400 400
July 2022(2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400 400


Term	Type(1)	Notional Amount Outstanding
		September 30, 2021		December 31, 2020
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		400
July 2023(2)	Forward-starting to pay a fixed rate of 3.78% and receive a floating rate	200		—
July 2024(2)	Forward-starting to pay a fixed rate of 3.88% and receive a floating rate	200		—

(1)Floating rates are based on 3-month LIBOR.

(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

(3)The July ~~2020~~2021 interest rate swaps were ~~terminated~~amended in ~~January 2020.~~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 ~~our~~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, wethe Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. WeThe Partnership also ~~use~~uses industry standard commercial agreements which allow for the netting of ~~positive and negative~~ exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

~~Our~~The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and ~~industrials,~~industrial end-users, oil and gas producers, ~~motor fuel distributors,~~ municipalities, gas and electric utilities, midstream companies and ~~midstream companies.~~independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic ~~factors~~ or regulatory changes that ~~could~~ impact ~~its~~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.

~~We have~~The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in ~~net~~our statement of operations or statement of comprehensive income ~~or other comprehensive income.~~(loss).

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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, 2020		December 31, 2019		September 30, 2020		December 31, 2019			September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
Derivatives designated as hedging instruments:	Derivatives designated as hedging instruments:									Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	Commodity derivatives (margin deposits)	$	32	$	24	$	(52)	$	0	Commodity derivatives (margin deposits)	$	2	$	25	$	(20)	$	(32)
											2		25		(20)		(32)
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)	68		319		(107)		(350)		Commodity derivatives (margin deposits)	330		90		(400)		(166)
Commodity derivatives	Commodity derivatives	47		41		(45)		(39)		Commodity derivatives	702		53		(661)		(71)
Interest rate derivatives	Interest rate derivatives	0		0		(522)		(399)		Interest rate derivatives	—		—		(376)		(448)
		115		360		(674)		(788)			1,032		143		(1,437)		(685)
Total derivatives	Total derivatives	$	147	$	384	$	(726)	$	(788)	Total derivatives	$	1,034	$	168	$	(1,457)	$	(717)

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, 2020		December 31, 2019		September 30, 2020		December 31, 2019			Balance Sheet Location	September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
Derivatives without offsetting agreements	Derivatives without offsetting agreements	Derivative liabilities	$	0	$	0	$	(522)	$	(399)	Derivatives without offsetting agreements	Derivative liabilities	$	—	$	—	$	(376)	$	(448)
Derivatives in offsetting agreements:	Derivatives in offsetting agreements:										Derivatives in offsetting agreements:
OTC contracts	OTC contracts	Derivative assets (liabilities)	47		41		(45)		(39)		OTC contracts	Derivative assets (liabilities)	702		53		(661)		(71)
Broker cleared derivative contracts	Broker cleared derivative contracts	Other current assets (liabilities)	100		343		(159)		(350)		Broker cleared derivative contracts	Other current assets (liabilities)	332		115		(420)		(198)
Total gross derivatives	Total gross derivatives		147		384		(726)		(788)		Total gross derivatives		1,034		168		(1,457)		(717)
Offsetting agreements:	Offsetting agreements:										Offsetting agreements:

Counterparty netting	Counterparty netting	Derivative assets (liabilities)	(28)		(18)		28		18		Counterparty netting	Derivative assets (liabilities)	(645)		(44)		645		44
Counterparty netting	Counterparty netting	Other current assets (liabilities)	(34)		(318)		34		318		Counterparty netting	Other current assets (liabilities)	(327)		(64)		327		64

Total net derivatives	Total net derivatives		$	85	$	48	$	(664)	$	(452)	Total net derivatives		$	62	$	60	$	(485)	$	(609)

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 ~~non-current~~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) 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,
			2020		2019		2020		2019				2021		2020		2021		2020
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	$	4	$	3	$	15	$	15	Commodity derivatives – Trading	Cost of products sold	$	14	$	4	$	12	$	15
Commodity derivatives – Non-trading	Commodity derivatives – Non-trading	Cost of products sold	(44)		21		53		(53)		Commodity derivatives – Non-trading	Cost of products sold	(71)		(44)		(206)		53

Interest rate derivatives	Interest rate derivatives	Gains (losses) on interest rate derivatives	55		(175)		(277)		(371)		Interest rate derivatives	Gains (losses) on interest rate derivatives	1		55		72		(277)

Total	Total		$	15	$	(151)	$	(209)	$	(409)	Total		$	(56)	$	15	$	(122)	$	(209)

13.~~RELATED PARTY TRANSACTIONS~~

The Partnership has related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.

~~The following table summarizes the revenues from related companies on our consolidated statements of operations:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 2020 2019
Revenues from related companies $ 100 $ 129 $ 375 $ 374

~~The following table summarizes the accounts receivable from related companies on our consolidated balance sheets:~~

September 30,
2020 December 31,
2019
Accounts receivable from related companies:
FGT $ 13 $ 50
Phillips 66 36 36
Various 41 73
Total accounts receivable from related companies $ 90 $ 159

~~As of September 30, 2020 and December 31, 2019, accounts payable with unconsolidated affiliates in the Partnership’s consolidated balance sheets totaled $30 million and $31 million, respectively.~~

~~Table of Contents~~

~~14.~~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 ~~last-in, first-out (“LIFO”).~~LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Table of Contents

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.

~~Table of Contents~~

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,
		2020		2019		2020		2019			2021		2020		2021		2020
Revenues:	Revenues:									Revenues:
Intrastate transportation and storage:	Intrastate transportation and storage:									Intrastate transportation and storage:
Revenues from external customers	Revenues from external customers	$	614	$	675	$	1,615	$	2,115	Revenues from external customers	$	1,112	$	614	$	5,940	$	1,615
Intersegment revenues	Intersegment revenues	40		89		148		270		Intersegment revenues	105		40		1,126		148
		654		764		1,763		2,385			1,217		654		7,066		1,763
Interstate transportation and storage:	Interstate transportation and storage:									Interstate transportation and storage:
Revenues from external customers	Revenues from external customers	466		475		1,365		1,454		Revenues from external customers	412		466		1,317		1,365
Intersegment revenues	Intersegment revenues	5		4		15		16		Intersegment revenues	6		5		33		15
		471		479		1,380		1,470			418		471		1,350		1,380
Midstream:	Midstream:									Midstream:
Revenues from external customers	Revenues from external customers	585		704		1,477		1,704		Revenues from external customers	560		585		1,709		1,477
Intersegment revenues	Intersegment revenues	792		876		2,088		2,792		Intersegment revenues	2,359		792		6,081		2,088
		1,377		1,580		3,565		4,496			2,919		1,377		7,790		3,565
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	2,207		2,271		5,991		7,340		Revenues from external customers	4,499		2,207		11,726		5,991
Intersegment revenues	Intersegment revenues	416		607		1,466		1,181		Intersegment revenues	763		416		2,048		1,466
		2,623		2,878		7,457		8,521			5,262		2,623		13,774		7,457
Crude oil transportation and services:	Crude oil transportation and services:									Crude oil transportation and services:
Revenues from external customers	Revenues from external customers	2,849		4,453		8,873		13,685		Revenues from external customers	4,577		2,849		12,497		8,873
Intersegment revenues	Intersegment revenues	1		0		4		0		Intersegment revenues	1		1		1		4
		2,850		4,453		8,877		13,685			4,578		2,850		12,498		8,877
Investment in Sunoco LP:	Investment in Sunoco LP:									Investment in Sunoco LP:
Revenues from external customers	Revenues from external customers	2,801		4,328		8,104		12,494		Revenues from external customers	4,772		2,801		12,626		8,104
Intersegment revenues	Intersegment revenues	4		3		53		4		Intersegment revenues	7		4		16		53
		2,805		4,331		8,157		12,498			4,779		2,805		12,642		8,157
Investment in USAC:	Investment in USAC:									Investment in USAC:
Revenues from external customers	Revenues from external customers	158		169		500		505		Revenues from external customers	156		158		464		500
Intersegment revenues	Intersegment revenues	3		6		9		15		Intersegment revenues	3		3		9		9
		161		175		509		520			159		161		473		509
All other:	All other:									All other:
Revenues from external customers	Revenues from external customers	275		420		995		1,196		Revenues from external customers	576		275		2,481		995
Intersegment revenues	Intersegment revenues	92		21		377		80		Intersegment revenues	120		92		303		377
		367		441		1,372		1,276			696		367		2,784		1,372
Eliminations	Eliminations	(1,353)		(1,606)		(4,160)		(4,358)		Eliminations	(3,364)		(1,353)		(9,617)		(4,160)
Total revenues	Total revenues	$	9,955	$	13,495	$	28,920	$	40,493	Total revenues	$	16,664	$	9,955	$	48,760	$	28,920

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Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019* 2020 2019*
Segment Adjusted EBITDA:
Intrastate transportation and storage $ 203 $ 235 $ 630 $ 777
Interstate transportation and storage 425 442 1,232 1,358
Midstream 530 411 1,280 1,205
NGL and refined products transportation and services 762 667 2,099 1,923
Crude oil transportation and services 631 726 1,741 2,222
Investment in Sunoco LP 189 192 580 497
Investment in USAC 104 104 315 310
All other 22 35 62 80
Adjusted EBITDA (consolidated) 2,866 2,812 7,939 8,372
Depreciation, depletion and amortization (912) (784) (2,715) (2,343)
Interest expense, net of interest capitalized (569) (579) (1,750) (1,747)
Impairment losses (1,474) (12) (2,803) (62)
Gains (losses) on interest rate derivatives 55 (175) (277) (371)
Non-cash compensation expense (30) (27) (93) (85)
Unrealized gains (losses) on commodity risk management activities (30) 64 (27) 90
Losses on extinguishments of debt 0 0 (62) (18)
Inventory valuation adjustments (Sunoco LP) 11 (26) (126) 71
Adjusted EBITDA related to unconsolidated affiliates (169) (161) (480) (470)
Equity in earnings (loss) of unconsolidated affiliates (32) 82 46 224
Impairment of investment in an unconsolidated affiliate (129) 0 (129) 0
Other, net 53 47 (48) 67
Income (loss) before income tax expense (360) 1,241 (525) 3,728
Income tax expense (41) (54) (168) (214)
Net income (loss) $ (401) $ 1,187 $ (693) $ 3,514

*As adjusted. See Note 1.

September 30,
2020 December 31, 2019*
Segment assets:
Intrastate transportation and storage $ 7,215 $ 6,648
Interstate transportation and storage 17,341 18,111
Midstream 19,056 20,332
NGL and refined products transportation and services 20,944 19,145
Crude oil transportation and services 19,882 22,933
Investment in Sunoco LP 4,986 5,438
Investment in USAC 3,011 3,730
All other 2,760 2,636
Total segment assets $ 95,195 $ 98,973

*As adjusted. See Note 1.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	172	$	203	$	3,209	$	630
Interstate transportation and storage	334		425		1,118		1,232
Midstream	556		530		1,321		1,280
NGL and refined products transportation and services	706		762		2,089		2,099
Crude oil transportation and services	496		631		1,490		1,741
Investment in Sunoco LP	198		189		556		580
Investment in USAC	99		104		299		315
All other	18		22		153		62
Adjusted EBITDA (consolidated)	2,579		2,866		10,235		7,939
Depreciation, depletion and amortization	(943)		(912)		(2,837)		(2,715)
Interest expense, net of interest capitalized	(558)		(569)		(1,713)		(1,750)
Impairment losses	—		(1,474)		(11)		(2,803)
Gains (losses) on interest rate derivatives	1		55		72		(277)
Non-cash compensation expense	(26)		(30)		(81)		(93)
Unrealized gains (losses) on commodity risk management activities	(19)		(30)		74		(27)
Inventory valuation adjustments (Sunoco LP)	9		11		168		(126)
Losses on extinguishments of debt	—		—		(8)		(62)
Adjusted EBITDA related to unconsolidated affiliates	(141)		(169)		(400)		(480)
Equity in earnings (losses) of unconsolidated affiliates	71		(32)		191		46
Impairment of investment in an unconsolidated affiliate	—		(129)		—		(129)
Other, net	11		53		—		(48)
Income (loss) before income tax expense	984		(360)		5,690		(525)
Income tax expense	(77)		(41)		(234)		(168)


Net income (loss)	$	907	$	(401)	$	5,456	$	(693)

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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, ~~2019~~2020 filed with the SEC on February ~~21, 2020.~~19, 2021. 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, ~~2019~~2020 filed with the SEC on February ~~21, 2020,~~19, 2021 and “Part II - Item 1A. Risk Factors” of our Quarterly ~~Reports~~Report on Form 10-Q for the quarter ended ~~March 31, 2020~~June 30, 2021 filed with the SEC on ~~May 11, 2020 and in this Quarterly Report on Form 10-Q.~~August 5, 2021. 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” mean Energy Transfer LP and its consolidated ~~subsidiaries, which include ETO. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.~~subsidiaries.

RECENT DEVELOPMENTS

~~COVID-19~~

In 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions. As a provider of critical energy infrastructure, our business has been designated as a “critical infrastructure sector” and our employees as “essential critical infrastructure workers” pursuant to the Department of Homeland Security Guidance on Essential Critical Infrastructure Workforce(s). To date, our field operations have continued uninterrupted, and remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the magnitude or duration of current and potential future COVID-19 mitigation measures. As an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities and we will continue to operate in accordance with federal and state health guidelines and safety protocols. We have implemented several new policies and provided employee training to help maintain the health and safety of our workforce.

~~ET Contribution of SemGroup Assets to ETO~~

~~On December 5, 2019, ET completed the acquisition of SemGroup. During the first and second quarters of 2020, ET contributed former SemGroup assets to ETO through sale and contribution transactions.~~

~~ETO~~ Series ~~F and Series G~~H Preferred Units Issuance

On ~~January 22, 2020, ETO~~June 15, 2021, the Partnership issued ~~500,000~~900,000 of its 6.500% Series ~~F Preferred Units at a price of $1,000 per unit and 1,100,000 of its Series G~~H Preferred Units at a price of $1,000 per unit. The net proceeds were used to repay amounts outstanding under ~~ETO's revolving credit facility~~the Partnership’s term loan and for general partnership purposes.

~~ETO January 2020 Senior Notes Offering~~Winter Storm Impacts

Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income and ~~Redemption~~Adjusted EBITDA and also affected the results of operations in certain segments, as discussed in “Results of Operations”. 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

On ~~January 22, 2020, ETO completed~~February 16, 2021, the Partnership entered into a ~~registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount~~definitive merger agreement to acquire Enable. Under the terms of the ~~Partnership’s 3.750% Senior Notes due 2030~~merger agreement, Enable’s common unitholders will receive 0.8595 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 of a Series G Preferred Unit, and ~~$2.00 billion aggregate principal amount~~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 ~~ETO’s 5.000% Senior Notes due 2050 (collectively, the “Notes”~~customary closing conditions, including Hart-Scott-Rodino Act (“HSR”) clearance.

The Federal Trade Commission (“FTC”) has issued requests for additional information and documentary material (the “Second Request”). The ~~Notes are~~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.

Rollup Mergers

On April 1, 2021, ET, ETO and ~~unconditionally guaranteed by~~certain of ETO’s ~~wholly-owned subsidiary,~~subsidiaries consummated several internal reorganization transactions (the “Rollup Mergers”). In connection with the Rollup Mergers, Sunoco Logistics Operations ~~on a senior unsecured basis.~~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:

~~Using proceeds from~~•All of ETO’s long-term debt was assumed by ET, as more fully described in Note 7 to the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.consolidated financial statements in “Item 1. Financial Statements.”

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~~Lake Charles LNG~~ •

~~On March 30, 2020, Royal Dutch Shell plc (“Shell”) announced that it would not proceed with a proposed equity interest in~~Each issued and outstanding ETO preferred unit was converted into the ~~Lake Charles LNG liquefaction project due~~right to ~~adverse market factors affecting Shell's business and its desire to preserve cash in light~~receive one newly created ET preferred unit. A description of the ~~current environment. We intend to continue to develop the project, possibly~~ET Preferred Units is included in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure relatedNote 9 to the ~~existing regasification facility at the same site, including four LNG storage tanks,~~consolidated financial statements in “Item 1. Financial Statements.”

•Each of ETO’s issued and outstanding Class K, Class L, Class M and Class N units, all of which were held by ETP Holdco Corporation, a wholly-owned subsidiary of ETO, were converted into an aggregate 675,625,000 newly created Class B Units representing limited partner interests in ET.

Sunoco LP’s Acquisitions

In September and October 2021, Sunoco LP acquired a total of nine refined product terminals in two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms.separate transactions for approximately $256 million.

Quarterly Cash Distribution

In October ~~2020,~~2021, ET announced its quarterly distribution of $0.1525 per unit ($0.61 annualized) on ET common units for the quarter ended September 30, 2020. On October 26, 2020 we announced a cash distribution for the third quarter of $0.1525 per unit ($0.61 annualized) on ET common units. This distribution represents a 50% decrease as compared to the distribution for the prior quarter. The Partnership intends to use the excess cash flow resulting from this distribution decrease to reduce its level of indebtedness. The Partnership will continue to evaluate its cash distribution policy in light of its leverage ratio and its capital expenditure outlook in order to preserve its investment grade credit ratings.2021.

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~~cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC 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 ~~not be~~ precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors' income tax costs. On July 31, 2020, the United States Court of Appeals for the District of ~~Colombia~~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 ~~entities’~~entity’s ability to argue in support of recovery of an income tax allowance and the ~~impacts~~court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of the FERC's policy on the treatment of income taxes ~~may have~~ on the rates ~~ETO~~we can charge for ~~the FERC regulated~~FERC-regulated transportation services ~~are~~is unknown at this time.

~~The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) on March 15, 2018, requesting comments on the effect~~Even without application of the ~~Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to~~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 ~~whether,~~based on many components, including ROE and tax-related components, although changes in these components may tend to decrease our cost-of-service rate, other components in the cost-of-service rate calculation may increase 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. 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 ~~so how,~~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 ~~should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on~~ or ~~before May 21, 2018.~~ 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 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

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charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle filed a cost and revenue study on April 1, ~~2019. Panhandle filed a~~2019 and an NGA Section 4 rate case on August 30, 2019.

~~In March 2019, following the decision~~ The Section 4 and Section 5 proceedings were consolidated by order of the ~~D.C. Circuit~~Chief Judge on October 1, 2019. A hearing in ~~Emera Maine v. Federal Energy Regulatory Commission,~~ the ~~FERC~~combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. The initial decision by the administrative law judge was issued ~~a Notice of Inquiry regarding~~on March 26, 2021. On April 26, 2021, Panhandle filed its ~~policy for determining return~~brief on ~~equity (“ROE”). The FERC specifically sought~~

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~~information and stakeholder views~~exceptions to ~~help~~ the FERC explore whether, and if so how, it should modify its policies concerning the determination of ROE to be used in designing jurisdictional rates charged by public utilities. The FERC also expressly sought comment on whether any changes to its policies concerning public utility ROEs should be applied to interstate natural gas and oil pipelines. Initial comments were due in June 2019, and reply comments were due in July 2019.initial decision. On May ~~21, 2020, the FERC issued a Policy Statement~~17, 2021, Panhandle filed its reply brief on ~~Determining Return on Equity for Natural Gas and Oil Pipelines establishing a revised policy for determining ROE, including the use of the Capital Asset Pricing Model in addition~~exception to the ~~Discounted Cash Flow Model for determining ROE and clarification regarding the formation of proxy groups for establishing a pipeline’s ROE.~~

Even without application of the FERC’s recent policy statements on income tax allowance or ROE or any additional action with respect to the 2017 Tax Law NOI, 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 including the allowance for income taxes and the amount for accumulated deferred income taxes but also other pipeline costs that will continue to affect the FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP, 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. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or other regulations resulting from the March 15, 2018 proposals. 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 ETO’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.initial decision.

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. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were ~~due~~filed by us on ~~or before July 25, 2018.~~May 26, 2021. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Common Carrier Regulation

The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG plus 1.23 percent. Many existing pipelines utilize theIn a December 2020 order, FERC liquids index to change transportation rates annually every July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of the FERC Form No. 6. This information will be used by the FERC in its next five year review of the liquids pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. On June 18, 2020, the FERC issued a Notice of Inquiry requesting comments on a proposed oil pipeline index fordetermined that during the five-year period commencing July 1, 2021 and ending June 30, 2026, ~~using the~~common carriers charging indexed rates will be permitted to adjust their indexed ceilings annually by PPI-FG plus ~~0.09% as~~0.78 percent. Requests for rehearing of the ~~index level,~~December 2020 order were filed on January 19, 2021, and ~~requested comments on whether and how the index should reflect the Revised Policy Statement and~~remain pending before FERC. Accordingly, the FERC’s treatment of accumulated deferred income taxes as well as the FERC’s revised ROE methodology. Comments on the indexing rate methodology Notice of Inquiry were due August 17, 2020, with reply comments due September 11, 2020. The FERC’s establishment of a just and reasonable rate, including thefinal determination of the ~~appropriate liquids pipeline~~ index ~~is based on many~~rate coupled with the anticipated and subsequent appeals of 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 ~~and as noted, the FERC’s tax related changes will affect two such components,~~are the allowance for income taxes and the amount for accumulated deferred income ~~taxes, while the FERC’s ROE policy~~taxes. These changes will primarily impact any cost-of-service related filing and other pipeline costs also will continue to affect the FERC’s determination of the appropriate pipeline index. Accordingly, depending on the FERC’s application of its indexing rate methodology for the next five year term of index

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~~rates, the Revised Policy Statement and tax effects related to the Tax Act may impact~~ our revenues associated with any ~~transportation services we may provide pursuant to cost of~~cost-based service ~~based rates in the~~could be adversely affected by future ~~including indexed rates.~~

~~Trends and Outlook~~

Recent market disruptions involving the COVID-19 pandemic have negatively impacted our earnings and cash flows from operations and may continue to do so. Reduced demand for natural gas, NGLs, refined products and/FERC or crude oil caused by the COVID-19 pandemic and a continuation of low WTI crude oil prices may result in the continued shut-in of production from U.S. oil and gas wells, which in turn may result in decreased volumes transported on our pipeline systems and decreased overall utilization of our midstream services.

With respect to commodity prices, natural gas prices have strengthened in recent months as a reduction in crude oil production has led to decreased supplies of associated natural gas from these wells. Natural gas fundamentals point to an undersupplied market over the upcoming winter with demand outpacing supply in the near term. Meanwhile, crude oil prices saw a sharp decline as a result of actions by foreign oil-producing nations and a decrease in global demand as result of the COVID-19 pandemic but have subsequently risen and stabilized. We cannot predict the future impacts, or the duration of such impacts, from the COVID-19 pandemic.

The outlook for commodity prices is mixed and could have a varying impact on our business. Reduced demand and increased supply of crude oil has resulted in an increase in worldwide crude oil storage inventories, which is expected to keep crude oil prices depressed for the near term. With respect to natural gas markets, a relatively more moderate decrease in demand, coupled with the previously mentioned decreases in gas production associated with wells drilled to produce crude oil, have more than counterbalanced the reduction in demand. The overall outlook for our midstream services will depend, in part, on the timing and extent of recovery in the commodity markets.

While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors.

While the vast majority of our counterparties are investment grade rated companies, some of our counterparties may be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court, in which case we may pursue legal action to prevent such a rejection. For example, following the request of one of our FERC-regulated natural pipelines, the FERC commenced an investigation into whether the public interest requires abrogation or modification of a firm transportation agreement and an interruptible transportation agreement with one of our shippers. We anticipate FERC will issue a final ruling in the proceeding in mid-November 2020; however, actual determination regarding the contract will depend upon further action by the counterparty and any further bankruptcy-related proceedings. If a counterparty is successful in rejecting an existing contract in bankruptcy, we expect that we would attempt to negotiate replacement contracts with those counterparties and, depending on the availability of alternatives to our services, these contracts may have terms that are less favorable to us than the contracts rejected in bankruptcy court.

Ultimately, the extent to which our business will be impacted by recent market developments depends on the factors described above as well as future developments beyond our control, which are highly uncertain and cannot be predicted. In response to these market events and uncertainties, we have cut our already reduced 2020 growth capital spending budget by a total of $700 million and reduced planned operating expenses by approximately $500 million. While current market volatility makes the near-term unpredictable,judicial rulings. However, we believe that ~~overall the long-term demand for our services~~these impacts, if any, will continue given the essential nature of the midstream natural gas, NGLs, refined products and crude oil businesses, although we cannot predict any possible changes in such demand with reasonable certainty.

We currently have ample liquidity to fund our business and we do not anticipate any liquidity concerns in the immediate future (see “Liquidity and Capital Resources” below). In addition, while the trading price of ET common units declined significantly during the first nine months of 2020, thereby making equity capital market transactions less attractive in the near term, we continue to have access to the debt capital markets on generally favorable terms. In the event we seek additional equity or debt capital, our blended cost of capital for equity and debt is expected to be ~~modestly higher in the near term; however, we will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future in light of this higher cost of capital.~~minimal.

Results of Operations

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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 ~~last-in, first-out (“LIFO”).~~LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.

As discussed in Note 1 of the Partnership’s consolidated financial statements included in “Item 1. Financial Statements,” during the first quarter of 2020, the Partnership elected to change its inventory accounting policy related to certain barrels of crude oil that were previously accounted for as inventory. These changes have been applied retrospectively to all prior periods, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

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Consolidated Results

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019* Change 2020 2019* Change
Segment Adjusted EBITDA:
Intrastate transportation and storage $ 203 $ 235 $ (32) $ 630 $ 777 $ (147)
Interstate transportation and storage 425 442 (17) 1,232 1,358 (126)
Midstream 530 411 119 1,280 1,205 75
NGL and refined products transportation and services 762 667 95 2,099 1,923 176
Crude oil transportation and services 631 726 (95) 1,741 2,222 (481)
Investment in Sunoco LP 189 192 (3) 580 497 83
Investment in USAC 104 104 — 315 310 5
All other 22 35 (13) 62 80 (18)
Adjusted EBITDA (consolidated) 2,866 2,812 54 7,939 8,372 (433)
Depreciation, depletion and amortization (912) (784) (128) (2,715) (2,343) (372)
Interest expense, net of interest capitalized (569) (579) 10 (1,750) (1,747) (3)
Impairment losses (1,474) (12) (1,462) (2,803) (62) (2,741)
Gains (losses) on interest rate derivatives 55 (175) 230 (277) (371) 94
Non-cash compensation expense (30) (27) (3) (93) (85) (8)
Unrealized gains (losses) on commodity risk management activities (30) 64 (94) (27) 90 (117)
Losses on extinguishments of debt — — — (62) (18) (44)
Inventory valuation adjustments (Sunoco LP) 11 (26) 37 (126) 71 (197)
Adjusted EBITDA related to unconsolidated affiliates (169) (161) (8) (480) (470) (10)
Equity in earnings (loss) of unconsolidated affiliates (32) 82 (114) 46 224 (178)
Impairment of investment in an unconsolidated affiliate (129) — (129) (129) — (129)
Other, net 53 47 6 (48) 67 (115)
Income (loss) before income tax expense (360) 1,241 (1,601) (525) 3,728 (4,253)
Income tax expense (41) (54) 13 (168) (214) 46
Net income (loss) $ (401) $ 1,187 $ (1,588) $ (693) $ 3,514 $ (4,207)

*As adjusted.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Change		2021		2020		Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	172	$	203	$	(31)	$	3,209	$	630	$	2,579
Interstate transportation and storage	334		425		(91)		1,118		1,232		(114)
Midstream	556		530		26		1,321		1,280		41
NGL and refined products transportation and services	706		762		(56)		2,089		2,099		(10)
Crude oil transportation and services	496		631		(135)		1,490		1,741		(251)
Investment in Sunoco LP	198		189		9		556		580		(24)
Investment in USAC	99		104		(5)		299		315		(16)
All other	18		22		(4)		153		62		91
Adjusted EBITDA (consolidated)	2,579		2,866		(287)		10,235		7,939		2,296
Depreciation, depletion and amortization	(943)		(912)		(31)		(2,837)		(2,715)		(122)
Interest expense, net of interest capitalized	(558)		(569)		11		(1,713)		(1,750)		37
Impairment losses	—		(1,474)		1,474		(11)		(2,803)		2,792
Gains (losses) on interest rate derivatives	1		55		(54)		72		(277)		349
Non-cash compensation expense	(26)		(30)		4		(81)		(93)		12
Unrealized gains (losses) on commodity risk management activities	(19)		(30)		11		74		(27)		101
Inventory valuation adjustments (Sunoco LP)	9		11		(2)		168		(126)		294
Losses on extinguishments of debt	—		—		—		(8)		(62)		54
Adjusted EBITDA related to unconsolidated affiliates	(141)		(169)		28		(400)		(480)		80
Equity in earnings (losses) of unconsolidated affiliates	71		(32)		103		191		46		145
Impairment of investment in an unconsolidated affiliate	—		(129)		129		—		(129)		129
Other, net	11		53		(42)		—		(48)		48
Income (loss) before income tax expense	984		(360)		1,344		5,690		(525)		6,215
Income tax expense	(77)		(41)		(36)		(234)		(168)		(66)


Net income (loss)	$	907	$	(401)	$	1,308	$	5,456	$	(693)	$	6,149

Adjusted EBITDA (consolidated).For the three months ended September 30, ~~2020~~2021 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 2% due to the net effects of multiple drivers within several of the Partnership’s segments. Among these impacts, the most significant were an increase of $104 million related to the restructuring and assignment of certain gathering and processing contracts in our midstream segment and an increase of $88 million in marketing margin in our NGL and refined products transportation and services segment primarily driven by higher optimization gains from the sale of NGL component products. The increase in Adjusted EBITDA also reflected a net increase of approximately $150 million from recent acquisitions and assets placed in service. These increases in Adjusted EBITDA were partially offset by multiple other changes, the most significant of which were the impacts of lower volumes and market prices among several of our core operating segments resulting primarily from COVID-19 related demand reductions.

~~For the nine months ended September 30, 2020 compared to the same period last year, Adjusted EBITDA decreased 5%~~29%, primarily due to the impacts of ~~lower volumes~~Winter Storm Uri in February 2021. The most significant impacts from the storm were recognized in our intrastate transportation and ~~market prices among several~~storage segment, where realized storage margin increased by $1.52 billion compared to the prior period as a result of withdrawals during the storm. In addition, realized natural gas sales increased $936 million and retained fuel revenues increased $114 million in our ~~core operating segments resulting~~intrastate transportation and storage segment, and these increases were also primarily ~~from COVID-19 related demand reductions. These decreases were partially offset by an increase~~due to the impacts of ~~$156 million~~the storm.

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~~from our NGL~~Additional information on changes impacting Adjusted EBITDA for the three and ~~refined products transportation and services segment primarily due to higher throughput volumes, an increase of $79 million from our midstream segment primarily due~~nine months ended September 30, 2021 compared to the ~~contract restructuring discussed above,~~same periods last year, including other impacts from Winter Storm Uri and ~~an increase of $83 million from our investment~~other non-storm-related factors, is available below in Sunoco LP segment primarily due to increased gross profit per gallon sold. The increase in Adjusted EBITDA also reflected a net increase of approximately $440 million from recent acquisitions and assets placed in service.“Segment Operating Results.”

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and nine months ended September 30, ~~2020~~2021 compared to the same ~~periods~~period last year primarily due to ~~the acquisition of SemGroup on December 5, 2019, as well as~~ incremental depreciation related to assets recently placed in service.

Interest Expense, ~~Net of Interest Capitalized.~~net. Interest expense, net of interest capitalized decreased for the three ~~months ended September 30, 2020 compared to the same period last year primarily due to the following:~~

•~~a decrease of $7 million recognized by the Partnership due to lower borrowing costs on both recently refinanced~~ and ~~floating rate debt, and higher capitalized interest;~~

•a decrease of $1 million for USAC for the three months ended September 30, 2020 compared to the same period last year was primarily attributable to lower weighted average interest rates under its credit agreement, offset by increased borrowings under its credit agreement; and

•~~a decrease of $2 million for Sunoco LP for the three months ended September 30, 2020 compared to the same period last year primarily related to a slight decrease in average total long-term debt.~~

~~Interest expense, net of interest capitalized increased for the~~ nine months ended September 30, ~~2020~~2021 compared to the same periods last year primarily due to the following:

•the Partnership’s interest ~~expenses recognized by~~expense decreased $8 million and $30 million for the ~~Partnership was unchanged~~three and nine months ended September 30, 2021, respectively, primarily due to lower total debt outstanding and lower borrowing costs on ~~both~~ recently refinanced and floating rate debt, ~~and higher capitalized~~partially offset by lower interest ~~offsetting a higher consolidated debt balance;~~capitalized; and

•~~an increase of of $2~~Sunoco LP’s interest expense decreased $3 million and $7 million for ~~USAC~~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, ~~2020 compared to the nine months ended September 30, 2019 was primarily attributable to~~2021, impairment losses included a ~~full nine months~~total of ~~interest expense incurred in the current period on its senior notes issued March 2019, partially offset~~$5 million recognized by ~~reduced borrowings and lower weighted average interest rates under the credit agreement; and~~

•~~an increase of $1 million for Sunoco LP for the nine months ended September 30, 2020 compared to the same period last year primarily~~USAC related to its compression equipment, as well as a ~~slight increase in average total long-term debt.~~

~~Impairment Losses.~~ During the three months ended March 31, 2020, the Partnership performed an interim impairment test on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result of the interim impairment test, the Partnership recognized a goodwill$6 million impairment of ~~$483 million~~intangible assets related to ~~our Arklatex and South Texas operations~~customer contracts within the midstream segment, a goodwill impairment of $183 million related to our Lake Charles LNG regasification operations with the interstate transportation and storage segment, and a goodwill impairment of $40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. DuringPartnership’s crude operations.

For the three months ended September 30, 2020, the Partnership ~~performed interim impairment testing on certain reporting units within its midstream, interstate, crude, NGL~~recognized goodwill impairments totaling $1.46 billion and all other operations. As a result, the Partnership recognized an impairment of $1.28 billion related to our crude operations, a goodwill impairment of $132 million related to our SemCAMS operations, a goodwill impairment of $43 million and a fixed asset ~~impairment of~~impairments totaling $19 million ~~related to our interstate operations~~ primarily due to decreases in projected future cash flow as a result of the overall market demand decline. In addition, USAC recognized ~~a goodwill~~an equipment impairment of ~~$619~~$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 ~~three months ended March 31,~~first quarter of 2020 ~~which is included~~totaling $706 million due to decreases in ~~the Partnership’s consolidated results of operations. During the three months ended March 31, 2019, USAC recorded a $3 million impairment of compression equipment~~projected future cash flows as a result of ~~its evaluations~~overall market demand decline and a goodwill impairment recognized by USAC of ~~the future deployment~~$619 million, as well as an equipment impairment of ~~USAC’s idle fleet under then-current market conditions. USAC recorded~~ $4 million ~~and $2 million impairment of compression equipment~~based on changes in market conditions during the ~~three months ended June 30, 2020 and September 30, 2020, respectively, as a result~~second quarter of ~~its evaluations of the future deployment of its idle fleet under current market conditions.~~2020.

Gains (Losses) on Interest Rate Derivatives. Gains and losses on interest rate derivatives during the three and nine months ended September 30, ~~2020~~2021 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. ~~See additional information~~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 ~~(losses) on commodity risk management activities~~and losses within each segment are included in “Segment Operating Results” ~~below.~~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.”

~~Table~~Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of ~~Contents~~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 in fuel prices reduced lower of cost or market reserve requirements by $9 million and $11 million, respectively. For the nine months ended September 30, 2021, an increase in fuel prices reduced lower of cost or market reserve requirements for the period by $168 million. For the nine months ended September 30, 2020, a decline in fuel prices increased lower of cost or market reserve requirements for the period by $126 million, resulting in an adverse impact to net income.

Losses on Extinguishments of Debt. During the ~~three and~~nine months ended September 30, 2021, the losses on extinguishments of debt also included 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~~ETO’s senior notes redemption in January 2020.

~~Inventory Valuation Adjustments.~~ ~~Inventory valuation adjustments were recorded for the inventory associated with Sunoco LP due to changes in fuel prices between periods.~~

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 ~~months ended September 30, 2020 compared to the same period in the prior year, income tax expense decreased due to lower earnings at our corporate subsidiaries in the current period. For the~~and nine months ended September 30, ~~2020~~2021 compared to the same ~~period in the prior~~periods last year, income tax expense ~~decreased~~increased due to ~~the recognition of a taxable gain on the sale of assets and~~ higher earnings ~~at our~~from the Partnership’s consolidated corporate ~~subsidiaries in the prior period.~~subsidiaries.

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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,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Equity in earnings (losses) of unconsolidated affiliates:	Equity in earnings (losses) of unconsolidated affiliates:													Equity in earnings (losses) of unconsolidated affiliates:
Citrus	Citrus	$	50	$	44	$	6	$	127	$	115	$	12	Citrus	$	44	$	50	$	(6)	$	123	$	127	$	(4)
FEP		(106)		15		(121)		(158)		43		(201)
FEP (1)														FEP (1)	—		(106)		106		—		(158)		158
MEP	MEP	(1)		1		(2)		(3)		15		(18)		MEP	(5)		(1)		(4)		(12)		(3)		(9)
White Cliffs	White Cliffs	2		—		2		19		—		19		White Cliffs	(1)		2		(3)		—		19		(19)
Other	Other	23		22		1		61		51		10		Other	33		23		10		80		61		19
Total equity in earnings (losses) of unconsolidated affiliates	Total equity in earnings (losses) of unconsolidated affiliates	$	(32)	$	82	$	(114)	$	46	$	224	$	(178)	Total equity in earnings (losses) of unconsolidated affiliates	$	71	$	(32)	$	103	$	191	$	46	$	145

Adjusted EBITDA related to unconsolidated affiliates(1):
Adjusted EBITDA related to unconsolidated affiliates(2):														Adjusted EBITDA related to unconsolidated affiliates(2):
Citrus	Citrus	$	96	$	92	$	4	$	264	$	260	$	4	Citrus	$	87	$	96	$	(9)	$	251	$	264	$	(13)
FEP	FEP	19		19		—		57		56		1		FEP	—		19		(19)		—		57		(57)
MEP	MEP	8		13		(5)		23		52		(29)		MEP	4		8		(4)		14		23		(9)
White Cliffs	White Cliffs	11		—		11		38		—		38		White Cliffs	4		11		(7)		14		38		(24)
Other	Other	35		37		(2)		98		102		(4)		Other	46		35		11		121		98		23
Total Adjusted EBITDA related to unconsolidated affiliates	Total Adjusted EBITDA related to unconsolidated affiliates	$	169	$	161	$	8	$	480	$	470	$	10	Total Adjusted EBITDA related to unconsolidated affiliates	$	141	$	169	$	(28)	$	400	$	480	$	(80)

Distributions received from unconsolidated affiliates:	Distributions received from unconsolidated affiliates:													Distributions received from unconsolidated affiliates:
Citrus	Citrus	$	48	$	54	$	(6)	$	155	$	128	$	27	Citrus	$	106	$	48	$	58	$	191	$	155	$	36
FEP	FEP	20		20		—		55		53		2		FEP	—		20		(20)		4		55		(51)
MEP	MEP	4		7		(3)		22		33		(11)		MEP	1		4		(3)		9		22		(13)
White Cliffs	White Cliffs	2		—		2		25		—		25		White Cliffs	5		2		3		25		25		—
Other	Other	24		22		2		63		80		(17)		Other	26		24		2		73		63		10
Total distributions received from unconsolidated affiliates	Total distributions received from unconsolidated affiliates	$	98	$	103	$	(5)	$	320	$	294	$	26	Total distributions received from unconsolidated affiliates	$	138	$	98	$	40	$	302	$	320	$	(18)

(1)For the three and nine months ended September 30, 2020, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership’s equity in earnings by $123 million and $208 million, respectively.

(2)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

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The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:

•Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.

•Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included

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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 following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. 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 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.

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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,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Natural gas transported (BBtu/d)	Natural gas transported (BBtu/d)	12,185		12,560		(375)		12,745		12,221		524		Natural gas transported (BBtu/d)	12,335		12,185		150		12,465		12,745		(280)
Withdrawals from (injections to) storage natural gas inventory (BBtu)		10,315		—		10,315		15,380		—		15,380
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
Revenues	Revenues	$	654	$	764	$	(110)	$	1,763	$	2,385	$	(622)	Revenues	$	1,217	$	654	$	563	$	7,066	$	1,763	$	5,303
Cost of products sold	Cost of products sold	434		501		(67)		985		1,473		(488)		Cost of products sold	978		434		544		3,636		985		2,651
Segment margin	Segment margin	220		263		(43)		778		912		(134)		Segment margin	239		220		19		3,430		778		2,652
Unrealized (gains) losses on commodity risk management activities	Unrealized (gains) losses on commodity risk management activities	23		19		4		(16)		3		(19)		Unrealized (gains) losses on commodity risk management activities	(1)		23		(24)		(18)		(16)		(2)
Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(42)		(48)		6		(131)		(137)		6		Operating expenses, excluding non-cash compensation expense	(64)		(42)		(22)		(199)		(131)		(68)
Selling, general and administrative expenses, excluding non-cash compensation expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(7)		(7)		—		(22)		(20)		(2)		Selling, general and administrative expenses, excluding non-cash compensation expense	(8)		(7)		(1)		(25)		(22)		(3)
Adjusted EBITDA related to unconsolidated affiliates	Adjusted EBITDA related to unconsolidated affiliates	7		7		—		19		18		1		Adjusted EBITDA related to unconsolidated affiliates	6		7		(1)		19		19		—
Other	Other	2		1		1		2		1		1		Other	—		2		(2)		2		2		—
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	203	$	235	$	(32)	$	630	$	777	$	(147)	Segment Adjusted EBITDA	$	172	$	203	$	(31)	$	3,209	$	630	$	2,579

Volumes. For the three months ended September 30, ~~2020~~2021 compared to the same period last year, transported volumes increased primarily due to production increases in the Permian.

For the nine months ended September 30, 2021 compared to the same period last year, transported volumes decreased primarily due to the bankruptcy filing of a transportation ~~customer. For the nine months ended September 30, 2020 compared to the same period last year, transported volumes increased primarily due to increased utilization~~customer, a contract step-down, and impacts of ~~our Texas pipelines, partially offset by the bankruptcy filing of a transportation customer.~~

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Winter Storm Uri.

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,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Transportation fees	Transportation fees	$	151	$	150	$	1	$	460	$	452	$	8	Transportation fees	$	162	$	151	$	11	$	542	$	460	$	82
Natural gas sales and other (excluding unrealized gains and losses)	Natural gas sales and other (excluding unrealized gains and losses)	75		112		(37)		231		405		(174)		Natural gas sales and other (excluding unrealized gains and losses)	39		75		(36)		1,167		231		936
Retained fuel revenues (excluding unrealized gains and losses)	Retained fuel revenues (excluding unrealized gains and losses)	12		14		(2)		31		37		(6)		Retained fuel revenues (excluding unrealized gains and losses)	29		12		17		145		31		114
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	5		6		(1)		40		21		19		Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	8		5		3		1,558		40		1,518
Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustments		(23)		(19)		(4)		16		(3)		19
Unrealized gains on commodity risk management activities and fair value inventory adjustments														Unrealized gains on commodity risk management activities and fair value inventory adjustments	1		(23)		24		18		16		2
Total segment margin	Total segment margin	$	220	$	263	$	(43)	$	778	$	912	$	(134)	Total segment margin	$	239	$	220	$	19	$	3,430	$	778	$	2,652

Segment Adjusted EBITDA. For the three months ended September 30, ~~2020~~2021 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment decreased due to the net ~~impacts~~effects of the following:

•a decrease of ~~$37~~ $36 million in realized natural gas sales and other primarily due to lower ~~realized gains~~optimization volumes with shifts to long-term third-party contracts from ~~pipeline optimization activity;~~the Permian to the Gulf Coast and lower spreads; and

•~~a decrease~~an increase of $2$22 million in operating expenses primarily due to increases of $9 million in cost of fuel consumption due to higher gas prices, $6 million in maintenance project costs, $3 million in employee related expenses, and $3 million in ad valorem taxes; partially offset by

•an increase of $11 million in transportation fees due to increased firm transportation volumes from the Permian;

•an increase of $17 million in retained fuel revenues primarily due to ~~lower~~higher natural gas prices; and

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•~~a decrease~~an increase of $1$3 million in realized storage margin due to ~~lower realized gains from financial derivatives used to hedge physical~~higher storage ~~gas; partially offset by~~

•~~a decrease of $6 million in operating expenses primarily due to $2 million decrease in employee costs, a $2 million decrease in maintenance project costs and a $1 million decrease in outside services.~~optimization.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2020~~2021 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment ~~decreased~~increased due to the net ~~impacts~~effects of the following:

•~~a decrease~~an increase of ~~$174~~$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 ~~lower realized gains from pipeline optimization activity;~~natural gas sales during Winter Storm Uri;

•~~a decrease~~an increase of $6$114 million in retained fuel revenues primarily due to ~~lower~~higher natural gas ~~prices;~~prices during Winter Storm Uri; and

•an increase of $2$82 million in ~~selling, general and administrative expenses primarily~~transportation fees due to ~~higher allocated corporate costs;~~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 ~~$19 million in realized storage margin primarily due to higher realized gains on financial hedges used to hedge physical storage gas;~~

•an increase of $8 million in transportation fees primarily due to volume ramp-ups on the Red Bluff Express pipeline and new contracts, partially offset by the expiration of certain contracts on Regency Intrastate Gas System;

•~~a decrease of $6~~$68 million in operating expenses primarily due to ~~a decrease~~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 ~~a decrease of $4~~$3 million in outside services ~~partially offset by an increase of $1 million in allocated costs~~ and ~~an increase of $1 million in utilities; and~~material costs.

•~~an increase of $1 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher fee revenue on the Trans-Pecos and Comanche Trail pipelines.~~

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Interstate Transportation and Storage


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Natural gas transported (BBtu/d)	Natural gas transported (BBtu/d)	10,387		11,407		(1,020)		10,422		11,254		(832)		Natural gas transported (BBtu/d)	9,917		10,387		(470)		9,769		10,422		(653)
Natural gas sold (BBtu/d)	Natural gas sold (BBtu/d)	15		17		(2)		16		18		(2)		Natural gas sold (BBtu/d)	16		15		1		18		16		2
Revenues	Revenues	$	471	$	479	$	(8)	$	1,380	$	1,470	$	(90)	Revenues	$	418	$	471	$	(53)	$	1,350	$	1,380	$	(30)

Operating expenses, excluding non-cash compensation, amortization and accretion expenses	Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(147)		(141)		(6)		(429)		(425)		(4)		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	Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(20)		(17)		(3)		(57)		(49)		(8)		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	Adjusted EBITDA related to unconsolidated affiliates	122		124		(2)		343		368		(25)		Adjusted EBITDA related to unconsolidated affiliates	91		122		(31)		265		343		(78)

Other	Other	(1)		(3)		2		(5)		(6)		1		Other	(2)		(1)		(1)		(5)		(5)		—
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	425	$	442	$	(17)	$	1,232	$	1,358	$	(126)	Segment Adjusted EBITDA	$	334	$	425	$	(91)	$	1,118	$	1,232	$	(114)

Volumes. For the three and nine months ended September 30, ~~2020~~2021 compared to the same periods last year, transported volumes decreased primarily due to ~~lower crude production resulting in lower associated gas production~~foundation shipper contract expirations and a ~~decrease in demand for LNG export.~~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, ~~2020~~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 $8$53 million in revenues primarily due to a ~~decrease of $16~~$37 million decline resulting from shipper contract expirations on our Tiger system and an $18 million decline due to a ~~contractual rate adjustment~~shipper bankruptcy during 2020 also on ~~commitments at~~ our ~~Lake Charles LNG facility effective January 2020 and a decrease of $9~~Tiger system. In addition, transportation revenues decreased by $16 million ~~due to less capacity sold~~ on our Panhandle and Trunkline ~~systems.~~systems due to lower demand. These decreases were partially offset by ~~increased margin~~an increase of $13 million in transportation revenue from ~~short-term firm contracts on~~ our ~~Transwestern and~~ Rover ~~systems due to increased demand and higher parking due to the timing~~system as a result of ~~transactions;~~more favorable market conditions;

•an increase of $6$5 million in operating ~~expense~~expenses primarily due to ana $7 million increase from the revaluation of system gas, a $5 million increase in ~~bad debt reserves~~maintenance project costs, a $3 million increase in employee costs, and ~~higher~~$2 million increase in ad valorem ~~taxes,~~taxes; partially offset by a decrease in credit losses in the ~~impact of cost cutting initiatives;~~prior period;

•an increase of $3$1 million in selling, general and administrative expenses primarily ~~resulting from legal~~due to higher allocated overhead costs and ~~consulting fees related to an ongoing rate case~~employee costs; and ~~a shipper bankruptcy; and~~

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•a decrease of $2$31 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to ~~lower earnings~~a $19 million decrease from our Fayetteville Express Pipeline joint venture as a result of $6the expiration of foundation shipper contracts, a $9 million decrease from our Citrus joint venture due to a contractual rate adjustment and a $3 million decrease from our Midcontinent Express Pipeline ~~primarily as a result of~~joint venture due to lower rates ~~received following the expiration of certain contracts, partially offset by a $4 million increase from Citrus primarily due to higher margins and lower operating expenses.~~on short-term capacity.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2020~~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 ~~$90~~$30 million in revenues primarily due to a ~~decrease of $48~~$97 million ~~due to~~decline resulting from shipper contract expirations on our Tiger system and a ~~contractual rate adjustment on commitments at our Lake Charles LNG facility effective January 2020, a decrease of $30~~$37 million decline due to a shipper bankruptcy ~~in 2019, a decrease of $28~~during 2020 also on our Tiger system. In addition, revenues decreased by $25 million ~~due to lower demand and lower rates~~ on our Panhandle and Trunkline systems ~~and a decrease of $5 million from~~due to lower ~~interruptible transportation resulting from lower customer demand and lower liquids as a result of multiple weather events and-third party maintenance on our Sea Robin and Trunkline systems.~~demand. These decreases were partially offset by increased ~~margins~~transportation revenues of $30 million from ~~higher reservation revenue on Transwestern, Tiger~~our Rover system, and ~~Rover resulting from higher contracted capacity and an~~a $96 million increase in ~~parking revenue on Panhandle and Trunkline;~~operational gas sales;

•an increase of $4 million in operating expenses primarily due to an increase in bad debt reserves and a decrease in the valuation of inventory on Panhandle in 2020, partially offset by lower employee costs and project expense resulting from cost cutting initiatives and lower ad valorem taxes due in part to appeals made to various taxing authorities;

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•~~an increase of $8~~$6 million in selling, general and administrative expenses primarily resulting from higher allocated overhead ~~costs, an increase in insurance premiums~~ and ~~higher legal and consulting fees related to an ongoing rate case and a shipper bankruptcy, partially offset by lower management incentive compensation;~~employee costs; and

•a decrease of ~~$25~~$78 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $57 million decrease from our Fayetteville Express Pipeline joint venture as a result of the expiration of foundation shipper contracts, a $13 million decrease from our Citrus joint venture due to higher project expenses and allocated costs as well as lower ~~earnings~~revenue resulting from a contractual rate adjustment, and an $8 million decrease from our Midcontinent Express Pipeline ~~primarily as a result of lower rates received following the expiration of certain contracts, partially offset by a $4 million increase from Citrus primarily~~joint venture due to ~~higher margins resulting from new contracts, rate increases on existing contracts and the recognition of a contract exit fee.~~capacity sold at lower rates.

Midstream


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Gathered volumes (BBtu/d)	Gathered volumes (BBtu/d)	12,904		13,955		(1,051)		13,071		13,278		(207)		Gathered volumes (BBtu/d)	12,991		12,904		87		12,712		13,071		(359)
NGLs produced (MBbls/d)	NGLs produced (MBbls/d)	635		574		61		616		567		49		NGLs produced (MBbls/d)	667		635		32		624		616		8
Equity NGLs (MBbls/d)	Equity NGLs (MBbls/d)	32		30		2		35		32		3		Equity NGLs (MBbls/d)	37		32		5		35		35		—
Revenues	Revenues	$	1,377	$	1,580	$	(203)	$	3,565	$	4,496	$	(931)	Revenues	$	2,919	$	1,377	$	1,542	$	7,790	$	3,565	$	4,225
Cost of products sold	Cost of products sold	668		953		(285)		1,716		2,678		(962)		Cost of products sold	2,153		668		1,485		5,864		1,716		4,148
Segment margin	Segment margin	709		627		82		1,849		1,818		31		Segment margin	766		709		57		1,926		1,849		77

Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(169)		(202)		33		(528)		(574)		46		Operating expenses, excluding non-cash compensation expense	(191)		(169)		(22)		(551)		(528)		(23)
Selling, general and administrative expenses, excluding non-cash compensation expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(21)		(21)		—		(67)		(63)		(4)		Selling, general and administrative expenses, excluding non-cash compensation expense	(28)		(21)		(7)		(80)		(67)		(13)
Adjusted EBITDA related to unconsolidated affiliates	Adjusted EBITDA related to unconsolidated affiliates	9		6		3		23		21		2		Adjusted EBITDA related to unconsolidated affiliates	8		9		(1)		23		23		—
Other	Other	2		1		1		3		3		—		Other	1		2		(1)		3		3		—
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	530	$	411	$	119	$	1,280	$	1,205	$	75	Segment Adjusted EBITDA	$	556	$	530	$	26	$	1,321	$	1,280	$	41

Volumes. Gathered volumes ~~decreased~~and NGL production increased during the three months ended September 30, ~~2020~~2021 compared to the same period last year primarily due to ~~decreases~~volume increases in the ~~South Texas~~Permian, Ark-La-Tex, and ~~Northeast~~South Texas regions, partially offset by ~~the impact of the SemGroup acquisition~~volume declines in the Northeast and Mid-Continent/Panhandle region and volume growth in the Permian region. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and increased ethane recovery in the Permian, South Texas and North Texas regions.

Gathered volumes and NGL production decreased during the nine months ended September 30, ~~2020~~2021 compared to the same period last year primarily due to volume decreases in the South Texas, ~~region,~~Mid-Continent/Panhandle, Northeast and North Texas regions partially offset by ~~the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and~~ volume growth in the Permian ~~region. NGL production increased due to the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region~~ and ~~increased ethane recovery in the Permian, South Texas and North Texas~~Ark-La-Tex regions.

~~Segment Margin~~. The table below presents the components of our midstream segment margin. For the prior period included in the table below, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees in order to conform to the current period classification:

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 Change 2020 2019 Change
Gathering and processing fee-based revenues $ 642 $ 550 $ 92 $ 1,675 $ 1,584 $ 91
Non-fee-based contracts and processing 67 77 (10) 174 234 (60)
Total segment margin $ 709 $ 627 $ 82 $ 1,849 $ 1,818 $ 31

4947

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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,
	2021		2020		Change		2021		2020		Change
Gathering and processing fee-based revenues	$	535	$	642	$	(107)	$	1,555	$	1,675	$	(120)
Non-fee-based contracts and processing	231		67		164		371		174		197

Total segment margin	$	766	$	709	$	57	$	1,926	$	1,849	$	77

Segment Adjusted EBITDA. For the three months ended September 30, ~~2020~~2021 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 ~~$92~~$156 million in non-fee-based margin due to favorable NGL prices of $96 million and natural gas prices of $60 million; 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 million in fee-based margin due to the recognition of $103 million related to the restructuring and assignment of certain gathering and processing contracts in the Ark-La-Tex region ~~which included~~in the ~~recognition~~third quarter of ~~$75 million of deferred revenue received in prior periods;~~2020;

•~~a decrease~~an increase of ~~$33~~$22 million in operating expenses due to ~~decreases~~an increase of ~~$17 million in outside services, $10~~$15 million in employee costs and $9$6 million in ~~materials;~~outside services; and

•an increase of $2$7 million in ~~non fee-based margin~~selling, general and administrative expenses due to ~~unfavorable NGL prices of $5 million and favorable gas prices of $7 million; partially offset by~~

•~~a decrease of $12 million in non fee-based margin due to decreased throughput volumes, primarily in the South Texas region.~~higher allocated overhead costs.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2020~~2021 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 ~~$91~~$319 million in non-fee-based margin due to favorable NGL prices of $197 million and natural gas prices of $122 million; and

•an increase of $21 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 $143 million in non-fee-based margin due to the impacts of Winter Storm Uri;

•a decrease of $120 million in fee-based margin due to ~~volume growth in the Mid-Continent/Panhandle region and~~ the recognition of $103 million related to the restructuring and assignment of certain gathering and processing contracts in the Ark-La-Tex region ~~which included~~in the ~~recognition~~third quarter of ~~$75 million of deferred revenue received~~2020, as well as volume declines in ~~prior periods; and~~the current period;

•~~a decrease~~an increase of ~~$46~~$23 million in operating expenses due to ~~decreases~~an increase of ~~$28~~$35 million in employee costs offset by a decrease of $9 million in outside services ~~$14~~and $2 million in ~~employee costs and $12 million in materials, partially offset by an increase of $9 million in maintenance project costs; partially offset by~~

•~~a decrease of $59 million in non-fee-based margin due to unfavorable NGL prices of $61 million and favorable gas prices of $2 million;~~

•~~a decrease of $1 million in non-fee-based margin due to decreased throughput volumes, primarily in the South Texas region;~~materials; and

•an increase of $4$13 million in selling, general and administrative expenses due to ~~an increase~~higher allocated overhead costs.

Table of ~~$3 million in insurance and an increase of $1 million in legal fees.~~Contents

NGL and Refined Products Transportation and Services

Three Months Ended
September 30, Nine Months Ended
September 30,
2020 2019 Change 2020 2019 Change
NGL transportation volumes (MBbls/d) 1,493 1,358 135 1,431 1,280 151
Refined products transportation volumes (MBbls/d) 460 552 (92) 460 599 (139)
NGL and refined products terminal volumes (MBbls/d) 850 872 (22) 813 845 (32)
NGL fractionation volumes (MBbls/d) 877 713 164 839 697 142
Revenues $ 2,623 $ 2,878 $ (255) $ 7,457 $ 8,521 $ (1,064)
Cost of products sold 1,712 1,962 (250) 4,916 6,136 (1,220)
Segment margin 911 916 (5) 2,541 2,385 156
Unrealized (gains) losses on commodity risk management activities 11 (81) 92 34 15 19
Operating expenses, excluding non-cash compensation expense (162) (167) 5 (475) (471) (4)
Selling, general and administrative expenses, excluding non-cash compensation expense (20) (22) 2 (64) (67) 3
Adjusted EBITDA related to unconsolidated affiliates 22 24 (2) 63 63 —
Other — (3) 3 — (2) 2
Segment Adjusted EBITDA $ 762 $ 667 $ 95 $ 2,099 $ 1,923 $ 176

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		Change		2021		2020		Change
NGL transportation volumes (MBbls/d)	1,803		1,493		310		1,685		1,431		254
Refined products transportation volumes (MBbls/d)	526		460		66		500		460		40
NGL and refined products terminal volumes (MBbls/d)	1,237		850		387		1,156		813		343
NGL fractionation volumes (MBbls/d)	884		877		7		815		839		(24)
Revenues	$	5,262	$	2,623	$	2,639	$	13,774	$	7,457	$	6,317
Cost of products sold	4,347		1,712		2,635		11,035		4,916		6,119
Segment margin	915		911		4		2,739		2,541		198
Unrealized (gains) losses on commodity risk management activities	(2)		11		(13)		(71)		34		(105)
Operating expenses, excluding non-cash compensation expense	(207)		(162)		(45)		(573)		(475)		(98)
Selling, general and administrative expenses, excluding non-cash compensation expense	(27)		(20)		(7)		(82)		(64)		(18)
Adjusted EBITDA related to unconsolidated affiliates	26		22		4		75		63		12

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

Volumes. ForFor the three and nine months ended September 30, ~~2020~~2021 compared to the same periods last year, NGL transportation volumes increased primarily due to the initiation of service on our propane and ethane export pipelines into our Nederland Terminal in the fourth quarter of 2020, higher ~~throughput~~volumes from the Eagle Ford region and higher volumes on our Mariner East and West pipeline ~~system. In addition, throughput barrels on our Texas~~systems. For the nine months ended September 30, 2021 compared to the same period last year, the increase in NGL ~~pipeline system increased due to higher receipt of liquids~~transportation volumes was partially offset by lower volumes caused by production ~~from both wholly-owned and third-party gas plants~~interruptions, primarily in the Permian ~~and North Texas regions.~~region, due to Winter Storm Uri during the first quarter of 2021.

Refined products transportation volumes ~~decreased~~increased for the three and nine months ended September 30, ~~2020~~2021 compared to the same periods last year due to ~~the closure of a third-party refinery during the third quarter of 2019, which negatively impacted supply to our refined products transportation system, and less domestic~~recovery from COVID-19 related demand ~~for jet fuel and other refined products. These decreases in volumes were partially offset by the initiation of service of our JC Nolan diesel fuel pipeline~~reduction in the ~~third quarter of 2019.~~prior period.

NGL and refined products terminal volumes ~~decreased~~increased for the three and nine months ended September 30, ~~2020~~2021 compared to the same periods last year primarily due to the ~~closure~~previously mentioned start of ~~a third-party refinery during the third quarter of 2019,~~new pipelines and ~~less domestic~~refined product demand for jet fuel and other refined products. These decreases were partially offset by higher volumes from our Mariner East system, and the initiation of service on our JC Nolan diesel fuel pipeline and natural gasoline export project, both of which commenced service in the third quarter of 2019.recovery.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility ~~increased~~decreased for the ~~three and~~ nine months ended September 30, ~~2020~~2021 compared to the same ~~periods~~period last year primarily due to lower NGL volumes feeding our Mont Belvieu fractionation facility as a result of production interruptions, primarily in the ~~commissioning~~Permian region, due to Winter Storm Uri during the first quarter of ~~our seventh fractionator in February 2020.~~2021.

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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,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Transportation margin	Transportation margin	$	494	$	474	$	20	$	1,419	$	1,259	$	160	Transportation margin	$	514	$	494	$	20	$	1,495	$	1,419	$	76
Fractionators and refinery services margin	Fractionators and refinery services margin	189		171		18		541		491		50		Fractionators and refinery services margin	182		189		(7)		510		541		(31)
Terminal services margin	Terminal services margin	130		175		(45)		410		478		(68)		Terminal services margin	166		130		36		470		410		60
Storage margin	Storage margin	63		57		6		181		166		15		Storage margin	63		63		—		200		181		19
Marketing margin	Marketing margin	46		(42)		88		24		6		18		Marketing margin	(12)		46		(58)		(7)		24		(31)
Unrealized gains (losses) on commodity risk management activities	Unrealized gains (losses) on commodity risk management activities	(11)		81		(92)		(34)		(15)		(19)		Unrealized gains (losses) on commodity risk management activities	2		(11)		13		71		(34)		105
Total segment margin	Total segment margin	$	911	$	916	$	(5)	$	2,541	$	2,385	$	156	Total segment margin	$	915	$	911	$	4	$	2,739	$	2,541	$	198

Segment Adjusted EBITDA. For the three months ended September 30, ~~2020~~2021 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment ~~increased~~decreased due to the net impacts of the following:

•~~an increase~~a decrease of ~~$88~~$58 million in marketing margin primarily due to a ~~$66~~$36 million ~~increase driven by higher~~decrease in optimization gains and from the sale of NGL component products at our Mont Belvieu facility and a ~~$12~~$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 ~~from capacity lease fees incurred by our marketing affiliate on our Mariner East pipeline system,~~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 ~~gasoline~~ 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 ~~optimization;~~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 ~~$13~~$30 million increase due to higher export volumes feeding into our Nederland Terminal, a $6 million increase from higher throughput ~~volumes~~ on our Mariner ~~East~~ pipeline system, and a $9$6 million increase ~~from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $4 million increase~~in refined products transportation due to ~~the initiation of service on our JC Nolan diesel fuel pipeline~~recovery from COVID-19 related demand reduction in the ~~third quarter of 2019,~~prior period and ~~a $3 million increase due to higher throughput volumes from the Barnett region.~~other refined products demand increases. These increases were partially offset by a $3$23 million decrease resulting from ~~the recognition of third party deferred revenue on our export pipeline in the third quarter of 2019,~~ a $2 million decrease due to less domestic demand for jet fuel and other refined products, and a $2 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019;

•~~an increase of $18 million in fractionators and refinery services margin primarily~~slightly lower average rate achieved due to the ~~commissioning~~increased utilization of our ~~seventh fractionator in February 2020 and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility;~~

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•a decrease of $5 million in operating expenses primarily due to a $9 million decrease in power costs, partially offset by increases totaling $4 million for costs associated with operating additional assets;ethane optimization strategy; and

•an increase of $6$4 million in ~~storage margin primarily~~Adjusted EBITDA related to unconsolidated affiliates due to ~~a $4 million~~an increase primarily ~~from a new intra-segment storage contract effective June 2020 and a $2 million increase in throughput fees generated primarily from exported volumes; partially offset by~~

•~~a decrease of $45 million in terminal services margin primarily due to a $40 million decrease~~ resulting from the expiration of a third party contract at our Nederland export facility in the second quarter of 2020, a $6 million decrease due to lower storage fees at our Marcus Hook Industrial Complex due to the closure of a third-party refinery during the third quarter of 2019, a $3 million decrease due to less domestic demand for jet fuel and other refined products, and a $2 million decrease due to the closure of a third-party refinery. These decreases were partially offset by an $11 million increase due to higher throughput on ~~our Mariner East system.~~Explorer pipeline due to COVID-19 demand recovery.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2020~~2021 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment ~~increased~~decreased due to the net impacts of the following:

•an increase of ~~$160~~$98 million in ~~transportation~~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 ~~$116~~$29 million increase from higher throughput volumes on our Mariner East pipeline system, a $55 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $18 million increasedecrease in northeast blending and optimization primarily due to ~~the initiation~~realized losses on financial instruments and increased costs related to RINs and intrasegment charges of ~~service of~~$28 million which were fully offset within our ~~JC Nolan diesel fuel pipeline in the third quarter of 2019, and a $13 million increase due to higher throughput volumes from the Barnett region.~~transportation margin. These ~~increases~~decreases were partially offset by a ~~$13~~$19 million ~~decrease resulting from the closure of a third-party refinery during the third quarter of 2019, a $13 million decrease~~increase in butane blending margin due to ~~less domestic demand for jet fuel~~more favorable spreads and ~~other refined products, a $12 million decrease~~additional blending days granted by the EPA due to the ~~reclassification of certain items,~~Colonial Pipeline shutdown, and ~~a $3~~an $8 million ~~decrease resulting from the recognition of third-party deferred revenue on our export pipeline~~increase due to inventory and other adjustments in the ~~third quarter of 2019;~~prior period;

•~~an increase~~a decrease of ~~$50~~$31 million in fractionators and refinery services margin primarily due to a ~~$47~~$44 million ~~increase~~decrease resulting from downtime on our various fractionators due to Winter Storm Uri in the ~~commissioning~~first quarter of 2021 and a slightly lower average rate achieved due to increased utilization of our sixth and seventh fractionators in February 2019 and February 2020, respectively, and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility, a $6 million increase due to a reclassification between our transportation and fractionators margins in the third quarter of 2019, and a $5 million increase in truck and rail volumes feeding our refinery services facility. These increases wereethane optimization strategy. This decrease was partially offset by a $5$10 million ~~decrease due primarily to an expiration of a third-party~~increase from blending ~~contract during the second quarter of 2020;~~activity at our fractionators facility; and

•an increase of $18 million in ~~marketing margin~~selling, general and administrative expenses primarily due to ~~higher optimization gains from the sale of NGL component products at our Mont Belvieu facility and a $12 million increase~~corporate cost reductions in gasoline blending and optimization. These increases were partially offset by a $47 million decrease due to lower margin from our butane blending business, an $18 million decrease in capacity lease fees incurred by our marketing affiliate on our Mariner East pipeline system, a $15 million decrease due to unfavorable hedge adjustments, and an $8 million decrease in NGL export and rack volumes; and

•an increase of $15 million in storage margin primarily due to a $10 million increase in throughput fees generated primarily from exported volumes and a $6 million increase resulting primarily from a new intra-segment storage contract effective June 2020; partially offset by

•an increase of $76 million in transportation margin primarily due to a $76 million increase due to higher export volumes feeding into our Nederland Terminal, a $39 million increase 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. These increases were partially offset by an $81 million decrease resulting from lower throughput across the various regions in Texas due to Winter Storm Uri related production outages and a slightly lower average rate achieved due to increased utilization of ~~$68~~our ethane optimization strategy;

•an increase of $60 million in terminal services margin primarily due to a ~~$64~~$49 million increase in ethane export fees at our Nederland Terminal, a $36 million increase in loading fees due to higher LPG export volumes at our Nederland Terminal, an $11 million increase due to higher throughput at our Marcus Hook Terminal and a $10 million increase due to higher throughput and storage at our refined product terminals 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 $44 million decrease resulting from an expiration of a third-party contract at our Nederland ~~export facility~~Terminal in the second quarter of ~~2020, a $26~~2020;

•an increase of $19 million ~~decrease~~in storage margin primarily due to ~~lower storage~~ fees ~~at our Marcus Hook Industrial Complex~~generated from exported volumes; and ~~lower refined product transport volumes~~

•an increase of $12 million in Adjusted EBITDA related to unconsolidated affiliates due to the closure of a third-party refinery during the third quarter of 2019, an $11 million decrease due to lower NGL volumes received into our Marcus Hook Industrial complex from third party pipelines, a $10 million decrease due to less domestic demand for jet fuel and other refined products, and a $7 million ~~decrease due to lower expense reimbursements in 2020. These decreases were partially offset by a $46 million~~ increase ~~due to~~primarily resulting from higher throughput on ~~our Mariner East system~~Explorer pipeline due to COVID-19 demand recovery and a $4$5 million increase ~~resulting~~ from ~~initiation of service of our natural gasoline export in the third quarter of 2019.~~higher volumes on White Cliffs pipeline.

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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,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Crude transportation volumes (MBbls/d)	Crude transportation volumes (MBbls/d)	3,587		4,223		(636)		3,880		4,180		(300)		Crude transportation volumes (MBbls/d)	4,173		3,551		622		3,901		3,840		61
Crude terminals volumes (MBbls/d)	Crude terminals volumes (MBbls/d)	2,276		2,322		(46)		2,662		2,575		87		Crude terminals volumes (MBbls/d)	2,703		2,317		386		2,553		2,688		(135)
Revenues	Revenues	$	2,850	$	4,453	$	(1,603)	$	8,877	$	13,685	$	(4,808)	Revenues	$	4,578	$	2,850	$	1,728	$	12,498	$	8,877	$	3,621
Cost of products sold	Cost of products sold	2,096		3,594		(1,498)		6,704		10,892		(4,188)		Cost of products sold	3,918		2,096		1,822		10,520		6,704		3,816
Segment margin	Segment margin	754		859		(105)		2,173		2,793		(620)		Segment margin	660		754		(94)		1,978		2,173		(195)
Unrealized (gains) losses on commodity risk management activities	Unrealized (gains) losses on commodity risk management activities	(1)		(2)		1		9		(100)		109		Unrealized (gains) losses on commodity risk management activities	14		(1)		15		12		9		3
Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(112)		(110)		(2)		(401)		(410)		9		Operating expenses, excluding non-cash compensation expense	(142)		(112)		(30)		(414)		(401)		(13)
Selling, general and administrative expenses, excluding non-cash compensation expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(28)		(21)		(7)		(82)		(61)		(21)		Selling, general and administrative expenses, excluding non-cash compensation expense	(44)		(28)		(16)		(102)		(82)		(20)
Adjusted EBITDA related to unconsolidated affiliates	Adjusted EBITDA related to unconsolidated affiliates	9		1		8		32		—		32		Adjusted EBITDA related to unconsolidated affiliates	7		9		(2)		15		32		(17)

Other	Other	9		(1)		10		10		—		10		Other	1		9		(8)		1		10		(9)
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	631	$	726	$	(95)	$	1,741	$	2,222	$	(481)	Segment Adjusted EBITDA	$	496	$	631	$	(135)	$	1,490	$	1,741	$	(251)

Volumes. For the three months ended September 30, ~~2020~~2021 compared to the same period last year, crude transportation volumes were ~~lower~~higher on our Texas pipeline system and ~~our~~ Bakken pipeline, ~~primarily~~ driven by ~~lower~~a recovery in crude oil production in these regions ~~and~~as

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a result of higher crude oil prices as well as a recovery in refinery ~~utilization due to COVID-19 related demand decreases, partly offset~~utilization. Volumes on our Bayou Bridge pipeline were also higher, driven by ~~contributions~~more favorable crude oil differentials for shippers. Volumes also benefited from ~~assets acquired in 2019.~~a full quarter of operations from our Cushing South pipeline. Crude terminal volumes were ~~lower primarily~~higher due to ~~lower pipeline volumes, refinery utilization, and impacts from weather events in the third quarter of 2020, partially offset by contributions from assets acquired in 2019.~~increased customer throughput activity at our Gulf Coast terminals.

For the nine months ended September 30, ~~2020~~2021 compared to the same period last year, crude transportation volumes were ~~lower~~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 ~~our Bakken pipeline,~~less favorable spreads for shippers to some markets in 2021. Crude terminal volumes were lower primarily ~~driven by lower production in these regions and lower refinery utilization~~ due to COVID-19 related demand decreases, partially offset by contributions from assets acquired in 2019. Terminal volumes were higher due to contributions from assets acquired in 2019, partially offset by lower pipeline volumes, refinery utilization, and impacts from weather events in the third quarter of 2020.reduced export demand.

Segment Adjusted EBITDA.For the three months ended September 30, ~~2020~~2021 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 of ~~$104~~$79 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a ~~$113~~$133 million decrease from our ~~Texas~~ crude ~~pipeline system~~oil acquisition and marketing business due to ~~lower utilization~~storage trading gains realized in the prior period, unfavorable crude inventory valuation adjustments, and ~~lower average tariff rates realized, an $84 million decrease due to lower volumes on~~less favorable pricing conditions impacting our Bakken ~~Pipeline from lower basin production, and~~to Gulf Coast trading operations, a $7$6 million decrease in throughput at our crude terminals primarily driven by lower ~~Permian~~export demand, and ~~Bakken~~a $3 million decrease from our Texas crude pipeline ~~volumes, reduced refinery utilization, and weather events in the third quarter of 2020 impacting operations,~~system due to lower average tariff rates realized; partially offset by a ~~$78~~$65 million increase ~~related to assets acquired in 2019~~from improved performance on our Bayou Bridge and a $31 million increase (excluding a net change of $2 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily due to trading gains realized from contango storage positions, as well as an inventory valuation write-down recognized in the prior period;Bakken pipelines;

•an increase of $2$30 million in operating expenses primarily due to ~~increased costs related to assets acquired in 2019, partially offset by lower~~higher volume-driven ~~pipeline~~expenses and higher employee expenses; ~~and~~

•an increase of $7$16 million in selling, general and administrative expenses primarily due to ~~a $3 million increase in~~ legal expenses and higher overhead allocations to the crude segment as a ~~$2 million increase in insurance expenses, a $1 million increase in information technology expenses,~~result of assets acquired; and ~~a $1 million increase in employee costs; partially offset by~~

•~~an increase~~a decrease of $8$2 million in Adjusted EBITDA related to unconsolidated affiliates due to ~~assets acquired~~lower volumes on White Cliffs pipeline from lower crude oil production, partially offset by an increase in ~~2019.~~jet fuel sales by our joint ventures.

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Segment Adjusted EBITDA. For the nine months ended September 30, ~~2020~~2021 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 of ~~$511~~$192 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a ~~$324~~$152 million decrease from our Texas crude pipeline system due to lower utilization and lower average tariff rates realized, a ~~$237~~$58 million decrease ~~(excluding a net change of $109 million in unrealized gains and losses on commodity risk management activities)~~ from our crude oil acquisition and marketing business primarily due ~~primarily~~ to storage trading gains realized in the prior period and less favorable pricing conditions impacting our ~~Permian to Gulf Coast and~~ Bakken to Gulf Coast trading operations, ~~as well as inventory valuation losses recognized in 2020,~~ partially offset by ~~trading gains realized from storage positions in 2020,~~favorable crude inventory valuation adjustments and a ~~$181 million decrease due to lower volumes on our Bakken Pipeline from lower basin production, and an $18~~$34 million decrease in throughput at our crude terminals primarily driven ~~lower Permian and Bakken volumes, lower refinery utilization, and weather events in the third quarter of 2020 impacting Gulf Coast operations,~~by reduced export demand; partially offset by ~~a $240 million increase related to assets acquired in 2019 and a $6~~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;

•~~a decrease~~an increase of $9$13 million in operating expenses primarily due to ~~lower~~higher volume-driven ~~pipeline~~ expenses ~~partially offset by increased costs related to assets acquired in 2019;~~ and higher employee expenses;

•an increase of ~~$21~~$20 million in selling, general and administrative expenses primarily due to ~~an $8 million increase in~~ legal expenses and higher overhead allocations to the crude segment as a ~~$4 million increase related to~~result of assets ~~acquired in 2019, a $4 million increase in insurance expenses, a $3 million increase in allocated overhead costs,~~acquired; and ~~a $1 million increase in information technology expenses; partially offset by~~

•~~an increase~~a decrease of ~~$32~~$17 million in Adjusted EBITDA related to unconsolidated affiliates due to ~~assets acquired~~lower volumes on White Cliffs pipeline from lower crude oil production, partially offset by an increase in ~~2019.~~jet fuel sales by our joint ventures.

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Investment in Sunoco LP


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Revenues	Revenues	$	2,805	$	4,331	$	(1,526)	$	8,157	$	12,498	$	(4,341)	Revenues	$	4,779	$	2,805	$	1,974	$	12,642	$	8,157	$	4,485
Cost of products sold	Cost of products sold	2,497		4,039		(1,542)		7,383		11,567		(4,184)		Cost of products sold	4,472		2,497		1,975		11,631		7,383		4,248
Segment margin	Segment margin	308		292		16		774		931		(157)		Segment margin	307		308		(1)		1,011		774		237
Unrealized gains on commodity risk management activities		(6)		(1)		(5)		—		(4)		4
Unrealized (gains) losses on commodity risk management activities														Unrealized (gains) losses on commodity risk management activities	2		(6)		8		(5)		—		(5)
Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(84)		(94)		10		(265)		(281)		16		Operating expenses, excluding non-cash compensation expense	(85)		(84)		(1)		(236)		(265)		29
Selling, general and administrative expenses, excluding non-cash compensation expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(24)		(36)		12		(76)		(91)		15		Selling, general and administrative expenses, excluding non-cash compensation expense	(23)		(24)		1		(67)		(76)		9
Adjusted EBITDA related to unconsolidated affiliates	Adjusted EBITDA related to unconsolidated affiliates	2		1		1		7		1		6		Adjusted EBITDA related to unconsolidated affiliates	3		2		1		7		7		—
Inventory valuation adjustments	Inventory valuation adjustments	(11)		26		(37)		126		(71)		197		Inventory valuation adjustments	(9)		(11)		2		(168)		126		(294)
Other	Other	4		4		—		14		12		2		Other	3		4		(1)		14		14		—
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	189	$	192	$	(3)	$	580	$	497	$	83	Segment Adjusted EBITDA	$	198	$	189	$	9	$	556	$	580	$	(24)

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the three months ended September 30, ~~2020~~2021 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 million primarily due to a 6.4% increase in gallons sold, partially offset by a 7.3% decrease in gross profit per gallon sold; and

•an increase in non-motor fuel sales of $5 million primarily due to increased credit card transactions, merchandise gross profit and franchise fee income.

Segment Adjusted EBITDA. For the nine months ended September 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment decreased due to the net impacts of the following:

•a decrease in the gross profit on motor fuel sales of ~~$23~~$62 million primarily due to a ~~4% increase~~14.8% decrease in gross profit per gallon sold, partially offset by a ~~12% decrease~~7.5% increase in gallons sold; ~~and~~

•~~a decrease of $3 million in non-motor fuel sales and lease gross margin as a result of rent concessions during the three months ended September 30, 2020;~~ partially offset by

•a decrease ~~of $22 million~~ in operating expenses and selling, general and administrative expenses of $38 million primarily ~~attributable~~due to lower employee costs ~~professional fees, credit card processing fees~~of and ~~advertising costs; and~~

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•~~an increase of $1 million in Adjusted EBITDA related to unconsolidated affiliates which was attributable to the JC Nolan joint venture entered into in 2019.~~

~~Segment Adjusted EBITDA.~~ For the nine months ended September 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment decreased due to the net impacts of the following:

•an increase in the gross profit on motor fuel sales of $62 million, primarily due to a 27% increase in gross profit per gallon sold and the receipt of a $13 million make-up payment under the fuel supply agreement with 7-Eleven, Inc., partially offset by a 14% decrease in gallons sold;

•~~a decrease of $31 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation expense, primarily attributable to~~ lower ~~employee costs, maintenance, advertising, credit card fees and utilities, which was partially offset by a $16 million charge for current~~ expected credit ~~losses on Sunoco LP’s accounts receivable in connection with the financial impact from COVID-19; and~~

•~~an increase in unconsolidated affiliate Adjusted EBITDA of $6 million, which was attributable to the JC Nolan joint venture entered into in 2019; partially offset by~~

•~~a decrease of $17 million in non motor fuel sales and lease gross profit primarily due to reduced credit card transactions related to the COVID-19 pandemic and rent concessions in 2020.~~losses.

Investment in USAC


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Revenues	Revenues	$	161	$	175	$	(14)	$	509	$	520	$	(11)	Revenues	$	159	$	161	$	(2)	$	473	$	509	$	(36)
Cost of products sold	Cost of products sold	20		23		(3)		62		69		(7)		Cost of products sold	19		20		(1)		61		62		(1)
Segment margin	Segment margin	141		152		(11)		447		451		(4)		Segment margin	140		141		(1)		412		447		(35)

Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(29)		(35)		6		(94)		(102)		8		Operating expenses, excluding non-cash compensation expense	(31)		(27)		(4)		(83)		(92)		9
Selling, general and administrative expenses, excluding non-cash compensation expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(11)		(13)		2		(41)		(39)		(2)		Selling, general and administrative expenses, excluding non-cash compensation expense	(10)		(10)		—		(30)		(40)		10

Other		3		—		3		3		—		3
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	104	$	104	$	—	$	315	$	310	$	5	Segment Adjusted EBITDA	$	99	$	104	$	(5)	$	299	$	315	$	(16)

The Investment in USAC segment reflects the consolidated results of USAC.

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Segment Adjusted EBITDA. For the three months ended September 30, ~~2020 Segment Adjusted EBITDA related to our investment in USAC segment was consistent with the same period last year primarily due to the offsetting impacts of the following:~~

•~~a decrease of~~ ~~$11 million in segment margin primarily driven by a decrease in U.S. crude oil and natural gas activity; offset by~~

•~~a decrease of $6 million in operating expenses primarily driven by a decrease in average revenue generating horsepower and reduced headcount; and~~

•~~a decrease of $2 million in selling, general and administrative expenses primarily due to a decrease in employee expenses.~~

~~Segment Adjusted EBITDA.~~ ~~For the nine months ended September 30, 2020~~2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment ~~increased~~decreased due to the following:

•a decrease of $1 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 and expenses related to our vehicle fleet.

Segment Adjusted EBITDA. For the nine months ended September 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment decreased due to the net impacts of the following:

•a decrease of $8$35 million in ~~operating expenses~~segment margin primarily ~~driven by a decrease in average~~due to lower revenue generating ~~horsepower and reduced headcount;~~horsepower; partially offset by

•a decrease of $4$9 million in ~~segment margin~~operating expenses primarily driven by a $7 million decrease in ~~revenues~~direct labor expenses and a $4 million decrease primarily due to sales tax refunds received in 2021; and

•a decrease of $10 million in selling, general and administrative expenses primarily due to a ~~reduction~~$6 million decrease in the provision for expected credit losses, a $2 million decrease in severance charges related to the departure of ~~ancillary maintenance work~~an executive and a $2 million decrease in ~~average revenue generating horsepower, offset by a decrease in costs of products sold of $7 million.~~employee-related expenses.

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All Other


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2020		2019		Change		2020		2019		Change			2021		2020		Change		2021		2020		Change
Revenues	Revenues	$	367	$	441	$	(74)	$	1,372	$	1,276	$	96	Revenues	$	696	$	367	$	329	$	2,784	$	1,372	$	1,412
Cost of products sold	Cost of products sold	318		393		(75)		1,110		1,138		(28)		Cost of products sold	652		318		334		2,464		1,110		1,354
Segment margin	Segment margin	49		48		1		262		138		124		Segment margin	44		49		(5)		320		262		58
Unrealized (gains) losses on commodity risk management activities		3		1		2		—		(4)		4
Unrealized losses on commodity risk management activities														Unrealized losses on commodity risk management activities	6		3		3		8		—		8
Operating expenses, excluding non-cash compensation expense	Operating expenses, excluding non-cash compensation expense	(35)		(39)		4		(100)		(52)		(48)		Operating expenses, excluding non-cash compensation expense	(29)		(35)		6		(118)		(100)		(18)
Selling, general and administrative expenses, excluding non-cash compensation expense	Selling, general and administrative expenses, excluding non-cash compensation expense	(23)		(11)		(12)		(80)		(45)		(35)		Selling, general and administrative expenses, excluding non-cash compensation expense	(13)		(23)		10		(71)		(80)		9
Adjusted EBITDA related to unconsolidated affiliates	Adjusted EBITDA related to unconsolidated affiliates	1		—		1		1		1		—		Adjusted EBITDA related to unconsolidated affiliates	2		1		1		1		1		—
Other and eliminations	Other and eliminations	27		36		(9)		(21)		42		(63)		Other and eliminations	8		27		(19)		13		(21)		34
Segment Adjusted EBITDA	Segment Adjusted EBITDA	$	22	$	35	$	(13)	$	62	$	80	$	(18)	Segment Adjusted EBITDA	$	18	$	22	$	(4)	$	153	$	62	$	91

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 ~~were acquired in the SemGroup acquisition in December 2019 and~~ include natural gas gathering and processing assets.

Segment Adjusted EBITDA. For the three months ended September 30, ~~2020~~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 ~~$10~~$12 million due to ~~lower compression market demand from our compression equipment business;~~the settlement of customer disputes related to prior period activity;

•a decrease of $6$7 million due to ~~power trading activities;~~the revaluation of natural gas inventory; and

•a decrease of ~~$11~~$2 million due to lower ~~demand and operator production, as well as a contract expiration at our natural resources business; and~~

•~~an increase of $10 million in merger and acquisition expense;~~trading gains; partially offset by

•an increase of ~~$26~~$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 ~~acquisition~~aggregate impact of ~~SemCAMS.~~multiples smaller changes; and

•an increase of $2 million due to lower utility expense.

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Segment Adjusted EBITDA. For the nine months ended September 30, ~~2020~~2021 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment ~~decreased~~increased primarily due to the net impacts of the following:

•~~a decrease~~an increase of ~~$15~~$60 million from power trading ~~activities;~~activities primarily due to short-term, favorable market conditions created by Winter Storm Uri in February of 2021;

•~~a decrease~~an increase of $6$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 million due to ~~increased power costs and increased expenses~~improved margins at our dual drive compression ~~services business;~~business resulting from more favorable market pricing conditions;

•~~a decrease~~an increase of ~~$31~~$12 million due to lower ~~compression market demand from our compression equipment business;~~merger and acquisition expenses;

•~~a decrease~~an increase of ~~$34~~$6 million from Energy Transfer Canada due to ~~higher merger and acquisition expense;~~the aggregate impact of multiples smaller changes;

•~~a decrease~~an increase of ~~$19~~$2 million due to ~~lower demand and operator production, as well as~~ a contract expiration at our natural resources ~~business; and~~

•~~a decrease of $6 million due to the elimination of Sunoco LP’s interest~~business in ~~our JC Nolan joint venture; partially offset by~~

•~~an increase of $77 million from the acquisition of SemCAMS;~~

•~~an increase of $16 million from settlement payments received from our ownership of PES;~~2020; and

•an increase of $4$2 million due to higher compressor sales and lower operating expenses in our compressor business; partially offset by

•a decrease of $22 million from ~~management fee income.~~2020 insurance proceeds received on settled claims related to our MTBE litigation.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

The Parent Company’s principal sources of cash flow are derived from distributions related to our investment in ETO, which derives its cash flows from its subsidiaries, including ETO’s investments in Sunoco LP and USAC.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with cash flows from its direct and indirect investments in ETO. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

The Parent Company expects ETO and its respective subsidiaries and investments in Sunoco LP and USAC to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as it deems prudent to provide liquidity for new capital projects of its subsidiaries or for other partnership purposes.

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.

We currently expect capital expenditures in ~~2020~~2021 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	$	5	$	15	$	40	$	45	Intrastate transportation and storage	$	15	$	25	$	30	$	35
Interstate transportation and storage (1)	Interstate transportation and storage (1)	50		75		115		120		Interstate transportation and storage (1)	50		75		115		120
Midstream	Midstream	405		430		115		120		Midstream	445		470		115		120
NGL and refined products transportation and services	NGL and refined products transportation and services	2,425		2,525		95		105		NGL and refined products transportation and services	650		725		110		120
Crude oil transportation and services (1)	Crude oil transportation and services (1)	225		250		105		115		Crude oil transportation and services (1)	275		325		90		100
All other (including eliminations)	All other (including eliminations)	75		100		50		55		All other (including eliminations)	90		115		45		55
Total capital expenditures	Total capital expenditures	$	3,185	$	3,395	$	520	$	560	Total capital expenditures	$	1,525	$	1,735	$	505	$	550

(1)Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline ~~projects.~~projects and our proportionate ownership of the Orbit Gulf Coast NGL export project.

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 ~~factors,~~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,~~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, ~~long-term debt, the issuance of additional preferred units or a combination thereof.~~along with cash from operations.

Sunoco LP currently expects to ~~spend~~invest approximately ~~$30~~$150 million onin growth capital expenditures and ~~$75~~approximately $45 million on maintenance capital expenditures for the full year ~~2020.~~2021.

USAC currently plans to spend approximately ~~$25~~$20 million onin maintenance capital expenditures and currently has budgeted between ~~$90~~$30 million and ~~$100~~$40 million in expansion capital expenditures for the full year ~~2020.~~2021.

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Cash Flows

Our cash flows may change in the future due to a number of factors, some of which we cannot control. These ~~factors~~ include regulatory changes, the price offor our ~~subsidiaries’~~ products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.

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Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” ~~above)~~), excluding the impacts of non-cash items and changes in operating assets and ~~liabilities (net of effects of acquisitions).~~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 ~~ETO has~~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 ~~purchases~~purchase and sales of inventories and the timing of advances and deposits received from customers.

Nine months ended September 30, ~~2020~~2021 compared to nine months ended September 30, ~~2019~~2020. Cash provided by operating activities during 2021 was $9.42 billion compared to $5.46 billion for 2020, and net income was $5.46 billion ~~compared to $5.97 billion~~ for ~~2019,~~2021 and net loss was $693 million for ~~2020 and net income was $3.51 billion for 2019.~~2020. The difference between net ~~loss~~income and net cash provided by operating activities for the nine months ended September 30, ~~2020~~2021 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of ~~$94~~$970 million and other non-cash items totaling ~~$5.91~~$2.79 billion.

The non-cash activity in ~~2020~~2021 and ~~2019~~2020 consisted primarily of depreciation, depletion and amortization of ~~$2.72~~$2.84 billion and ~~$2.34~~$2.72 billion, respectively, non-cash compensation expense of $81 million and $93 million, respectively, favorable inventory valuation adjustments of $168 million and ~~$85 million, respectively,~~unfavorable inventory valuation adjustments of $126 million, ~~and $71 million,~~ respectively, ~~and~~ deferred income taxes of $199 million and $159 million, respectively, losses on extinguishments of debt of $8 million and ~~$191~~$62 million, respectively, and impairment losses of $11 million and $2.80 billion, respectively. Non-cash activity also included ~~losses on extinguishments~~equity in earnings of ~~debt in 2020 and 2019~~unconsolidated affiliates of ~~$62~~$191 million and ~~$18 million, respectively, impairment losses of $2.80 billion and $62~~$46 million in ~~2020~~2021 and ~~2019,~~2020, respectively, and impairment of investment in an unconsolidated affiliate of $129 million in 2020.

~~Unconsolidated affiliate activity consisted of equity in earnings of $46 million and $224 million in 2020 and 2019, respectively, and~~Cash provided by operating activities includes cash distributions received offrom unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $226 million in 2021 and $176 million ~~and $254 million, respectively.~~in 2020.

Cash paid for interest, net of interest capitalized, was ~~$1.47~~$1.57 billion and ~~$1.57~~$1.47 billion for the nine months ended September 30, ~~2020~~2021 and ~~2019,~~2020, respectively. Interest capitalized was ~~$163~~$97 million and ~~$145~~$163 million for the nine months ended September 30, ~~2020~~2021 and ~~2019,~~2020, 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, ~~2020~~2021 compared to nine months ended September 30, ~~2019.~~2020. Cash used in investing activities during ~~2020~~2021 was ~~$3.86~~$1.91 billion compared to ~~$4.42~~$3.86 billion for ~~2019.~~2020. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for ~~2020~~2021 were ~~$3.97~~$2.02 billion compared to ~~$4.12~~$3.97 billion for ~~2019.~~2020. Additional detail related to our capital expenditures is provided in the table below. ~~During 2019, we received $93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary and paid $7 million in cash for all other acquisitions.~~

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The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover and Bayou Bridge pipeline projects and net of contributions in aid of construction costs) on an accrual basis for the nine months ended September 30, ~~2020:~~2021:


		Capital Expenditures Recorded During Period							Capital Expenditures Recorded During Period
		Growth		Maintenance		Total			Growth		Maintenance		Total
Intrastate transportation and storage	Intrastate transportation and storage	$	—	$	42	$	42	Intrastate transportation and storage	$	17	$	24	$	41
Interstate transportation and storage	Interstate transportation and storage	36		66		102		Interstate transportation and storage	24		72		96
Midstream	Midstream	322		82		404		Midstream	272		74		346
NGL and refined products transportation and services	NGL and refined products transportation and services	1,923		64		1,987		NGL and refined products transportation and services	508		77		585
Crude oil transportation and services	Crude oil transportation and services	164		56		220		Crude oil transportation and services	208		61		269
Investment in Sunoco LP	Investment in Sunoco LP	65		15		80		Investment in Sunoco LP	70		22		92
Investment in USAC	Investment in USAC	85		18		103		Investment in USAC	26		15		41
All other (including eliminations)	All other (including eliminations)	81		25		106		All other (including eliminations)	48		26		74
Total capital expenditures	Total capital expenditures	$	2,676	$	368	$	3,044	Total capital expenditures	$	1,173	$	371	$	1,544

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, ~~2020~~2021 compared to nine months ended September 30, ~~2019.~~2020. Cash used in financing activities during ~~2020~~2021 was ~~$1.61~~$7.57 billion compared to ~~$1.75~~$1.61 billion for ~~2019.~~2020. During ~~2020 and 2019, our subsidiaries received $1.58 billion and $780 million, respectively, in net proceeds from offerings of preferred units. During 2020,~~2021, we had a net ~~increase~~decrease in our debt level of ~~$358 million~~$6.00 billion compared to a net increase of ~~$878~~$358 million for ~~2019.~~2020. In ~~2020~~2021 and ~~2019,~~2020, we paid debt issuance costs of $3 million and $53 million, respectively. During 2021, we received $889 million from offerings of preferred units, and ~~$114 million, respectively.~~during 2020, our subsidiaries received $1.58 billion from offerings of preferred units.

In ~~2020~~2021 and ~~2019,~~2020, we paid distributions of ~~$2.40~~$1.38 billion and ~~$2.30~~$2.40 billion, respectively, to our partners. In ~~2020~~2021 and ~~2019,~~2020, we paid distributions of ~~$1.28~~$1.15 billion and ~~$1.27~~$1.28 billion, respectively, to noncontrolling interests. In 2021 and 2020, we paid distributions of $37 million to our redeemable noncontrolling interests. In addition, we received capital contributions of $114 million in cash from noncontrolling interests in 2021 compared to $203 million in cash from noncontrolling interests in ~~2020 compared to $278 million in cash from noncontrolling interests in 2019.~~2020.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

September 30,
2020 December 31,
2019
Parent Company Indebtedness:
ET Senior Notes due October 2020 $ — $ 52
ET Senior Notes due March 2023 5 5
ET Senior Notes due January 2024 23 23
ET Senior Notes due June 2027 44 44
Subsidiary Indebtedness:
ETO Senior Notes 37,783 36,118
Transwestern Senior Notes 400 575
Panhandle Senior Notes 235 235
Bakken Senior Notes 2,500 2,500
Sunoco LP Senior Notes and lease-related obligations 2,905 2,935
USAC Senior Notes 1,475 1,475
Credit facilities and commercial paper:
ETO $2.00 billion Term Loan facility due October 2022 2,000 2,000
ETO $5.00 billion Revolving Credit Facility due December 2023 (1)
3,231 4,214
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 87 162
USAC $1.60 billion Revolving Credit Facility due April 2023 497 403
HFOTCO Tax Exempt Notes due 2050 225 225
SemCAMS Revolver due February 2024 74 92
SemCAMS Revolver Term Loan A due February 2024 253 269
Other long-term debt 3 2
Net unamortized premiums, discounts, and fair value adjustments (12) 4
Deferred debt issuance costs (283) (279)
Total debt 51,445 51,054
Less: current maturities of long-term debt 21 26
Long-term debt, less current maturities $ 51,424 $ 51,028


	September 30, 2021		December 31, 2020
ET Indebtedness:
Senior Notes (1)	$	36,454	$	37,855
Term Loan (2)	—		2,000
Five-Year Credit Facility (2)	599		3,103
Subsidiary Indebtedness:
Transwestern Senior Notes	400		400
Panhandle Senior Notes	235		235
Bakken Senior Notes (3)	2,500		2,500
Sunoco LP Senior Notes and lease-related obligations	2,701		3,139
USAC Senior Notes	1,475		1,475
HFOTCO Tax Exempt Notes	225		225
Revolving credit facilities:
Sunoco LP Credit Facility	250		—
USAC Credit Facility	506		474
Energy Transfer Canada Revolving Credit Facility	81		57
Energy Transfer Canada Term Loan A	252		261
Energy Transfer Canada KAPS Facility	51		—

Other long-term debt	4		3
Net unamortized premiums, discounts, and fair value adjustments	(14)		(10)
Deferred debt issuance costs	(248)		(279)
Total debt	45,471		51,438
Less: current maturities of long-term debt	678		21
Long-term debt, less current maturities	$	44,793	$	51,417

(1)~~Includes $1.63 billion~~The balances presented above include senior notes that were formerly obligations of ETO prior to the Rollup Mergers discussed below and ~~$1.64 billion~~in “Recent Developments” above. As of ~~commercial paper outstanding at September 30, 2020~~March 31, 2021 and December 31, ~~2019,~~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 balance includes $650 million of 3.625% Senior Notes due April 2022 included in current maturities of long-term debt as of September 30, 2021.

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 ~~January 2020 Senior Notes Offering~~under the respective indentures and ~~Redemption~~credit agreements.

~~On January 22, 2020,~~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, the Partnership repaid the remaining $500 million balance and terminated the Term Loan.

During the first quarter of 2021, ETO ~~completed a registered offering (the “January 2020 Senior Notes Offering”)~~redeemed its $600 million aggregate principal amount of ~~$1.00~~4.40% senior notes due April 1, 2021 and its $800 million aggregate principal amount of 4.65% senior notes due June 1, 2021, using proceeds from the Five-Year Credit Facility.

During the third quarter of 2021, ET issued par call notices to redeem in full its $1.0 billion aggregate principal amount of ~~the Partnership’s 2.900% Senior Notes~~5.2% senior notes due ~~2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030~~February 1, 2022, and $2.00 billion aggregate principal amount of the Partnership’s 5.000% Senior Notes due 2050 (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis.

~~Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400~~$900 million aggregate principal amount of ~~5.75% Senior Notes~~5.875% senior notes due ~~September~~March 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET's $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern's $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.2022.

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The Partnership expects to redeem both series of senior notes during the fourth quarter of 2021, utilizing 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

~~ETO~~ 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$2.00 billion three-year term loan credit ~~facility (the “ETO Term Loan”). Borrowings under~~facility. During the ~~term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The ETO~~third quarter of 2021, the Term Loan ~~is unsecured~~was repaid in full and ~~is guaranteed by ETO’s subsidiary, Sunoco Logistics Operations.~~terminated.

~~As of September 30, 2020, the ETO Term Loan had $2 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of September 30, 2020 was 1.15%.~~

~~ETO~~ Five-Year Credit Facility

~~ETO~~ 364-Day Facility

Sunoco LP Credit Facility

~~Sunoco LP maintains a $1.50 billion senior secured revolving credit facility (the “Sunoco LP Credit Facility”), which matures in July 2023.~~ As of September 30, ~~2020,~~2021, the Sunoco LP Credit Facility had ~~$87~~$250 million of outstanding borrowings and $8$6 million in standby letters of ~~credit. As of~~credit and matures in July 2023. The amount available for future borrowings at September 30, ~~2020, Sunoco LP had $1.41 billion of availability under the Sunoco LP Credit Facility.~~2021 was $1.24 billion. The weighted average interest rate on the total amount outstanding as of September 30, ~~2020~~2021 was ~~2.15%~~2.09%.

USAC Credit Facility

~~USAC maintains a $1.60 billion senior secured revolving credit facility (the “USAC Credit Facility”), with a further potential increase of $400 million, which matures in April 2023.~~ As of September 30, ~~2020, the~~2021, USAC ~~Credit Facility~~ had ~~$497~~$506 million of outstanding borrowings ~~and no outstanding letters of credit.~~under the credit agreement. As of September 30, ~~2020,~~2021, USAC had ~~$1.10~~$1.09 billion of ~~borrowing base~~ availability under its credit facility, and subject to compliance with ~~the~~ applicable financial covenants, available borrowing capacity of ~~$412 million under the USAC Credit Facility.~~$114 million. The weighted average interest rate on the total amount outstanding as of September 30, ~~2020~~2021 was ~~3.03%~~2.96%.

~~SemCAMS~~Energy Transfer Canada Credit Facilities

~~SemCAMS is party to a credit agreement providing for a~~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$~~350~~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$65 million (US$~~262~~51 million at the September 30, ~~2020~~2021 exchange rate) ~~senior secured term loan facility, a C$525 million (US$394 million at the~~ ~~September 30, 2020~~ ~~exchange rate) senior secured revolving credit facility, and a C$300 million (US$225 million at the~~ ~~September 30, 2020~~ ~~exchange rate) senior secured construction loan facility (the “KAPS Facility”)~~. The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. SemCAMS may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$187 million at the ~~September 30, 2020~~ 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, 2020, the SemCAMS senior secured term loan facility and senior secured revolving credit facility had $253 million and $74 million, respectively, of outstanding borrowings. As of September 30, 2020, the KAPS Facility had no ~~outstanding borrowings.~~

Compliance with our Covenants ~~Related to Our Credit Agreements~~

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of September 30, ~~2020.~~2021.

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CASH DISTRIBUTIONS

Cash Distributions Paid by ~~the Parent Company~~ET

Under ~~the Parent Company~~its partnership agreement, ~~the Parent Company~~ET will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriate to provide for future cash requirements.

Cash Distributions on ET Common Units

Distributions declared and/or paid with respect to ET common units subsequent to December 31, ~~2019~~2020 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2019~~2020

February ~~7, 2020~~8, 2021

February 19, ~~2020~~2021

~~0.3050~~0.1525

March 31, ~~2020~~2021

May ~~7, 2020~~11, 2021

May 19, ~~2020~~2021

~~0.3050~~0.1525

June 30, ~~2020~~2021

August ~~7, 2020~~6, 2021

August 19, ~~2020~~2021

~~0.3050~~0.1525

September 30, ~~2020~~2021

November ~~6, 2020~~5, 2021

November 19, ~~2020~~2021

0.1525

Cash Distributions on ET 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 ET 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)

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)

(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 ET Preferred Units

A summary of the distribution and redemption rights associated with the ET Preferred Units is included in Note 9 in “Item 1. Financial Statements.”

Cash Distributions Paid by Subsidiaries

~~ETO,~~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, consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand ~~at the end of each quarter, less~~(less appropriate reserves determined by the ~~board~~boards of directors of their respective general ~~partners.~~

~~Cash Distributions Paid by ETO~~

~~Distributions on ETO preferred units declared and/or paid~~partners) subsequent to ~~December 31, 2019 were as follows:~~

Period Ended Record Date Payment Date
Series A (1)
Series B (1)
Series C Series D Series E
Series F (2)
Series G (2)
December 31, 2019 February 3, 2020 February 18, 2020 $ 31.25 $ 33.125 $ 0.4609 $ 0.4766 $ 0.4750 $ — $ —
March 31, 2020 May 1, 2020 May 15, 2020 — — 0.4609 0.4766 0.4750 21.19 22.36
June 30, 2020 August 3, 2020 August 17, 2020 31.25 33.125 0.4609 0.4766 0.4750 — —
September 30, 2020 November 2, 2020 November 16, 2020 — — 0.4609 0.4766 0.4750 33.75 35.63

~~(1)ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.~~

~~(2)ETO Series F and G Preferred Unit distributions related to~~ the ~~period ended March 31, 2020 represent a prorated initial distribution. Distributions are paid on a semi-annual basis.~~end of each quarter.

Cash Distributions Paid by Sunoco LP

Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP ~~to its common unitholders~~ subsequent to December 31, ~~2019~~2020 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2019~~2020

February ~~7, 2020~~8, 2021

February 19, ~~2020~~2021

0.8255

March 31, ~~2020~~2021

May ~~7, 2020~~11, 2021

May 19, ~~2020~~2021

0.8255

June 30, ~~2020~~2021

August ~~7, 2020~~6, 2021

August 19, ~~2020~~2021

0.8255

September 30, ~~2020~~2021

November ~~6, 2020~~5, 2021

November 19, ~~2020~~2021

0.8255

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Cash Distributions Paid by USAC

Distributions on USAC’s units declared and/or paid by USAC ~~to its common unitholders~~ subsequent to December 31, ~~2019~~2020 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, ~~2019~~2020

January ~~27, 2020~~25, 2021

February ~~7, 2020~~5, 2021

~~0.5250~~0.525

March 31, ~~2020~~2021

April ~~27, 2020~~26, 2021

May ~~8, 2020~~7, 2021

~~0.5250~~0.525

June 30, ~~2020~~2021

July ~~31, 2020~~26, 2021

August ~~10, 2020~~6, 2021

~~0.5250~~0.525

September 30, ~~2020~~2021

October ~~26, 2020~~25, 2021

November ~~6, 2020~~5, 2021

~~0.5250~~0.525

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership’s Annual Report on Form 10-K filed with the SEC on February ~~21, 2020. See Note 1 in “Item 1. Financial Statements” for information regarding recent changes to the Partnership’s critical accounting policies related to inventory.~~19, 2021.

RECENT ACCOUNTING PRONOUNCEMENTS

Currently, there are no accounting pronouncements that have been issued, but not yet adopted, that are expected to have a material impact on the Partnership’s financial position or results of operations.

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 are identified as any statement that does not relate strictly to historical or current facts. When used in this ~~annual~~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:

•changes in the long-term supply of and demand for natural gas, NGLs, refined products and/or crude oil, including as a result of uncertainty regarding the length of time it will take for the United States and the rest of the world to slow the spread of the COVID-19 virus to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities; such restrictions are designed to protect public health but also have the effect of reducing demand for natural gas, NGLs, refined products and crude oil;

•the severity and duration of world health events, including the recent COVID-19 pandemic, related economic repercussions, actions taken by governmental authorities and other third parties in response to the pandemic and the resulting severe disruption in the oil and gas industry and negative impact on demand for natural gas, NGLs, refined products and crude oil, which may negatively impact our business;

•changes in general economic conditions and changes in economic conditions of the crude oil and natural gas industries specifically, including the current significant surplus in the supply of oil and actions by foreign oil-producing nations with respect to oil production levels and announcements of potential changes in such levels, including the ability of those countries to agree on and comply with supply limitations;

•uncertainty regarding the timing, pace and extent of an economic recovery in the United States and elsewhere, which in turn will likely affect demand for natural gas, NGLs, refined products and crude oil and therefore the demand for midstream services we provide and the commercial opportunities available to us;

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•~~the deterioration of the financial condition of our customers and the potential renegotiation or termination of customer contracts as a result of such deterioration;~~

•operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;

•~~actions~~ taken by federal, state or local governments to require producers of natural gas, NGL, refined products and crude oil to proration or cut their production levels as a way to address any excess market supply situations;

•~~the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;~~

•~~the actual amount of cash distributions by our subsidiaries to us;~~

•the volumes transported on our ~~subsidiaries’~~ pipelines and gathering systems;

•the level of throughput in our ~~subsidiaries’~~ processing and treating facilities;

•the fees ~~our subsidiaries~~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;

•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, ~~NGL, refined products~~ and ~~crude oil~~NGL production;

•the availability of imported oil, natural gas ~~NGLs, refined products~~ and ~~crude oil;~~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 ~~NGLs, refined products~~ and ~~crude oil;~~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 ~~subsidiaries’~~ interstate and intrastate pipelines;

•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

•competition from other midstream companies and interstate pipeline companies;

•loss of key personnel;

•loss of key natural gas producers or the providers of fractionation services;

•reductions in the capacity or allocations of third-party pipelines that connect with our ~~subsidiaries~~ pipelines and facilities;

•the effectiveness of risk-management policies and procedures and the ability of our ~~subsidiaries~~ liquids marketing counterparties to satisfy their financial commitments;

•the nonpayment or nonperformance by our ~~subsidiaries’~~ customers;

•regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our ~~subsidiaries'~~ internal growth projects, such as our ~~subsidiaries'~~ construction of additional pipeline ~~systems or our subsidiaries’ continuing operations;~~systems;

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•risks associated with the construction of new pipelines and treating and processing facilities or additions to our ~~subsidiaries'~~ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;

•the availability and cost of capital and our ~~subsidiaries'~~ ability to access certain capital sources;

•a deterioration of the credit and capital markets;

•risks associated with the assets and operations of entities in which ~~our subsidiaries~~we own less than a controlling interests, including risks related to management actions at such entities that ~~our subsidiaries~~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; ~~and~~

•the costs and effects of legal and administrative ~~proceedings.~~proceedings; and

Many of the foregoing risks and uncertainties are, and will be, heightened by the COVID-19 pandemic and any further worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of •the risks ~~or uncertainties described in this Quarterly Report on Form 10-Q or~~associated with a potential failure to successfully combine our ~~Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.~~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, ~~2019,~~2020 filed with the SEC on February 19, 2021 and “Part II - Item 1A. Risk Factors” inof our Quarterly Report on Form 10-Q for the quarter ended ~~March 31, 2020, for the quarter ended~~ June 30, ~~2020 and in this Quarterly Reports~~2021 filed with the SEC on ~~Form 10-Q.~~August 5, 2021. 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, ~~2019~~2020 filed with the SEC on February ~~21, 2020,~~19, 2021, 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, ~~2019.~~2020. Since December 31, ~~2019,~~2020, there have been no material changes to our primary market risk exposures or how those exposures are managed.

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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, 2020					December 31, 2019						September 30, 2021					December 31, 2020
		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):
Basis Swaps IFERC/NYMEX (1)	Basis Swaps IFERC/NYMEX (1)	(91,365)	$	5	$	—	(35,208)	$	2	$	5	Basis Swaps IFERC/NYMEX (1)	(81,963)	$	10	$	1	(44,225)	$	2	$	5
Fixed Swaps/Futures	Fixed Swaps/Futures	4,965	1		1		1,483	—		—		Fixed Swaps/Futures	475	1		—		1,603	—		—

Power (Megawatt):	Power (Megawatt):											Power (Megawatt):
Forwards	Forwards	1,714,800	5		—		3,213,450	6		8		Forwards	712,400	15		—		1,392,400	4		—
Futures	Futures	(35,313)	—		—		(353,527)	1		2		Futures	(640,800)	(7)		—		18,706	(1)		—
Options – Puts	Options – Puts	(15)	—		—		51,615	1		—		Options – Puts	290,400	—		—		519,071	—		—
Options – Calls	Options – Calls	(6,323,560)	1		1		(2,704,330)	1		—		Options – Calls	36,704	(1)		—		2,343,293	1		—

(Non-Trading)	(Non-Trading)											(Non-Trading)
Natural Gas (BBtu):	Natural Gas (BBtu):											Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	Basis Swaps IFERC/NYMEX	(20,800)	(2)		—		(18,923)	(35)		15		Basis Swaps IFERC/NYMEX	(8,893)	(3)		—		(29,173)	—		1
Swing Swaps IFERC	Swing Swaps IFERC	(7,480)	(2)		—		(9,265)	—		4		Swing Swaps IFERC	(48,675)	4		1		11,208	(2)		—
Fixed Swaps/Futures	Fixed Swaps/Futures	(43,708)	(2)		13		(3,085)	(1)		1		Fixed Swaps/Futures	(45,588)	(55)		25		(53,575)	6		31
Forward Physical Contracts	Forward Physical Contracts	(15,281)	6		4		(13,364)	3		3		Forward Physical Contracts	(10,071)	3		—		(11,861)	4		5

NGLs (MBbls) – Forwards/Swaps	NGLs (MBbls) – Forwards/Swaps	(14,743)	(50)		49		(1,300)	(18)		18		NGLs (MBbls) – Forwards/Swaps	2,785	20		44		(5,840)	(100)		39
Refined Products (MBbls) – Futures	Refined Products (MBbls) – Futures	(3,391)	1		8		(2,473)	(2)		16		Refined Products (MBbls) – Futures	(3,272)	(3)		30		(2,765)	(8)		3
Crude (MBbls) – Forwards/Swaps	Crude (MBbls) – Forwards/Swaps	1,929	2		8		4,465	13		2		Crude (MBbls) – Forwards/Swaps	1,693	(13)		11		—	—		—
Corn (thousand bushels)		—	—		—		(1,210)	—		—

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	(38,490)	1		—		(31,780)	1		7		Basis Swaps IFERC/NYMEX	(21,255)	2		—		(30,113)	(1)		—
Fixed Swaps/Futures	Fixed Swaps/Futures	(38,490)	(23)		11		(31,780)	23		7		Fixed Swaps/Futures	(21,255)	(20)		12		(30,113)	(6)		8

(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, ~~2020,~~2021, we and our subsidiaries had ~~$6.97~~$2.51 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of ~~$70~~$25 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.

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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:

Term
Type(1)
Notional Amount Outstanding
September 30,
2020 December 31,
2019
July 2020(2)(3)
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate $ — $ 400
July 2021(2)
Forward-starting to pay a fixed rate of 3.55% and receive a floating rate 400 400
July 2022(2)
Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 400 400


Term	Type(1)	Notional Amount Outstanding
		September 30, 2021		December 31, 2020
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		400
July 2023(2)	Forward-starting to pay a fixed rate of 3.78% and receive a floating rate	200		—
July 2024(2)	Forward-starting to pay a fixed rate of 3.88% and receive a floating rate	200		—

(1)Floating rates are based on 3-month LIBOR.

(2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

(3)The July ~~2020~~2021 interest rate swaps were ~~terminated~~amended in ~~January 2020.~~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 ~~$297~~$253 million as of September 30, ~~2020.~~2021. 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 ~~Chief~~Co-Chief Executive ~~Officer~~Officers (“~~Principal~~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 ~~Officer~~Officers and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, ~~2020~~2021 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 ~~Officer~~Officers and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

~~During the~~ ~~three months endedSeptember 30, 2020~~, certain of the Partnership’s subsidiaries implemented an enterprise resource planning (“ERP”) system, in order to update existing technology and to integrate, simplify and standardize processes among the Partnership and its subsidiaries. Accordingly, we have made changes to our internal controls to address systems and/or processes impacted by the ERP implementation. Neither the ERP implementation nor the related control changes were undertaken in response to any deficiencies in the Partnership’s internal control over financial reporting.

~~Other than as discussed above, there~~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, ~~2020~~2021 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 ~~21, 2020~~19, 2021 and Note 10 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer LP and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, ~~2020.~~2021.

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 ~~will~~reasonably could result in monetary sanctions in excess of ~~$100,000.~~$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 a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupture occurred on the Noble to Douglas 8-inch pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP 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 OCC 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 Order and the matter is now closed.

For ~~a description of other legal proceedings,~~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 risk factors ~~described~~described in ~~“Part~~"Part I - Item 1A. Risk ~~Factors”~~Factors" in the Partnership's Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 filed with the SEC on February ~~21, 2020~~19, 2021.

Cybersecurity attacks, data breaches and ~~from the risk factors described in “Part II - Item 1A. Risk Factors” in the Partnership's Quarterly Reports on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 11, 2020.~~other disruptions affecting us, or our service providers, could materially and adversely affect our business, operations, reputation, and financial results.

~~Legal or regulatory actions related~~The security and integrity of our information technology infrastructure and physical assets are critical to ~~the Dakota Access Pipeline could cause an interruption to current or future operations, which could have an adverse effect on~~ our business and ~~results of operations.~~

~~On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit~~our ability to perform day-to-day operations and deliver services. In addition, in the ~~United States District Court for the District~~ordinary course of ~~Columbia~~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 (“~~District Court”~~DDoS”) ~~challenging permits issued~~attacks, ransomware attacks) that are beyond our control. These events can result from malfeasance by ~~the United States Army Corps of Engineers (“USACE”) permitting Dakota Access, LLC (“Dakota Access”)~~external parties, such as hackers, or due to ~~cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended~~human error by our or our service providers’ employees and contractors (e.g., due to challenge an easement issued by the USACE allowing 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”)social engineering or phishing attacks). On March 25, 2020, the court remanded the case back to the USACE for preparation of an Environment Impact Statement. On July 6, 2020, the court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and 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 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. The Court of Appeals also denied a motion to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether USACE will be required to prepare an Environmental Impact Statement. In addition, the Court of Appeals 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 expects USACE to clarify its position with respect to whether USACE intends to allow the continued operation of the pipeline notwithstanding the vacator of the easement and that the District Court may consider additional relief if necessary.

On August 10, 2020, the District Court ordered 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, USACE submitted a status report that indicated that it considers 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. Following the filing of this status report, the District Court ordered briefing on whether to enjoin the operation of the pipeline, with briefing scheduled to conclude by December 18, 2020.

Briefing on the merits of the appeal to the Court of Appeals has been completed, and oral argument has been scheduled by the Court of Appeals to occur on November 4, 2020. As a result of the ruling by the Court of Appeals related to the motions to stay

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COVID-19 pandemic has presented additional operational and ~~the District Court’s briefing schedule related~~cybersecurity risks to ~~the injunction issue, it~~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 ~~that~~to increase and attackers are becoming more sophisticated. We may be unable to anticipate, detect or prevent future attacks, particularly as the ~~pipeline will continue~~methodologies used by attackers change frequently or are not recognized until launched, and we may be unable to ~~operate during the pendency~~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 ~~the appeals process with the Court of Appeals.~~

~~While we believe that the pending lawsuits are unlikely to adversely affect the continued operation~~our information technology infrastructure or ~~potential expansion of the pipeline, we cannot assure this outcome. At this time, we cannot determine when~~physical assets, or ~~how these lawsuits will be resolved or the impact they may have on the Dakota Access project.~~

~~In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature~~other disruptions, could result in ~~interruptions~~damage to ~~construction~~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 ~~current~~operations. A successful cyberattack or ~~future projects, delays~~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 ~~completing those projects and/~~legal claims or proceedings, regulatory investigations and enforcement, penalties and fines, increased ~~project~~ 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 ana material adverse effect on our business and ~~results~~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, ~~operations.~~

any or all of our applicable insurance policies.

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ITEM 6. EXHIBITS

The exhibits listed below are filed or furnished, as indicated, as part of this report:


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~~(File No. ~~333-128097,~~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~~(File No. ~~1-32740,~~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~~(File No. ~~1-32740,~~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~~(File No. ~~1-32740,~~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~~(File No. ~~1-32740,~~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~~(File No. ~~1-32740,~~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~~(File No. ~~1-32740,~~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~~(File No. ~~1-32740,~~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 ~~as of~~ October 19, 2018 (incorporated by reference to Exhibit 3.9 of Form 10-Q ~~File~~(File No. ~~1-32740,~~1-32740) filed November 8, 2018)

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Exhibit Number						Description
3.10						Amendment No. 7 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated ~~as of~~ August 6, 2019 (incorporated by reference to Exhibit 3.10 of Form 10-Q ~~File~~(File No. ~~1-32740,~~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 ~~Chief~~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 ~~Chief~~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 as of September 30, 2020 and December 31, 2019;~~Sheets; (ii) our Consolidated Statements of ~~Operations for the three and nine months ended September 30, 2020 and 2019;~~Operations; (iii) our Consolidated Statements of Comprehensive Income (Loss) ~~for the three and nine months ended September 30, 2020 and 2019;~~; (iv) our Consolidated Statements of Partners’ ~~Capital for the three and nine months ended September 30, 2020 and 2019;~~Capital; (v) our Consolidated Statements of Cash ~~Flows for the nine months ended September 30, 2020 and 2019;~~Flows; and (vi) the notes to our Consolidated Financial ~~Statements.~~ Statements
104						Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
*						Filed ~~herewith.~~herewith
**						Furnished ~~herewith.~~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 ~~5, 2020~~4, 2021

By:

/s/ A. Troy Sturrock

A. Troy Sturrock

Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)

7168


PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets			15

Consolidated Statements of Operations			37

Consolidated Statements of Comprehensive Income (Loss)			48

Consolidated Statements of Equity			59

Consolidated Statements of Cash Flows			711

Notes to Consolidated Financial Statements			812

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			3738

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			6563

ITEM 4. CONTROLS AND PROCEDURES			6764

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS			6865

ITEM 1A. RISK FACTORS			6865









ITEM 6. EXHIBITS			7066

SIGNATURE			7168


	September 30, 2020		December 31, 2019*
ASSETS
Current assets:
Cash and cash equivalents	$	275	$	291
Accounts receivable, net	3,731		5,038
Accounts receivable from related companies	90		159
Inventories	1,723		1,532
Income taxes receivable	77		146
Derivative assets	19		23
Other current assets	235		275
Total current assets	6,150		7,464

Property, plant and equipment	93,239		89,790
Accumulated depreciation and depletion	(18,111)		(15,597)
	75,128		74,193

Advances to and investments in unconsolidated affiliates	3,068		3,460

Lease right-of-use assets, net	934		964

Other non-current assets, net	1,582		1,571
Intangible assets, net	5,915		6,154
Goodwill	2,418		5,167
Total assets	$	95,195	$	98,973


	Nine Months Ended September 30,
	2020		2019*
OPERATING ACTIVITIES:
Net income (loss)	$	(693)	$	3,514
Reconciliation of net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	2,715		2,343
Deferred income taxes	159		191
Inventory valuation adjustments	126		(71)
Non-cash compensation expense	93		85
Impairment losses	2,803		62
Impairment of investment in an unconsolidated affiliate	129		0
Losses on extinguishments of debt	62		18
Distributions on unvested awards	(33)		(27)
Equity in earnings of unconsolidated affiliates	(46)		(224)
Distributions from unconsolidated affiliates	176		254
Other non-cash	(130)		33
Net change in operating assets and liabilities, net of effects of acquisitions	94		(212)
Net cash provided by operating activities	5,455		5,966
INVESTING ACTIVITIES:
Cash proceeds from sale of noncontrolling interest in subsidiary	0		93
Cash paid for all other acquisitions, net of cash received	0		(7)
Capital expenditures, excluding allowance for equity funds used during construction	(4,030)		(4,181)
Contributions in aid of construction costs	61		63
Contributions to unconsolidated affiliates	(37)		(481)
Distributions from unconsolidated affiliates in excess of cumulative earnings	144		40
Proceeds from the sale of other assets	10		55
Other	(9)		(5)
Net cash used in investing activities	(3,861)		(4,423)
FINANCING ACTIVITIES:
Proceeds from borrowings	20,651		18,125
Repayments of debt	(20,293)		(17,247)

Subsidiary units issued for cash	1,580		780
Capital contributions from noncontrolling interests	203		278
Distributions to partners	(2,397)		(2,300)
Distributions to noncontrolling interests	(1,282)		(1,270)
Distributions to redeemable noncontrolling interest	(37)		0
Debt issuance costs	(53)		(114)
Other, net	18		(3)
Net cash used in financing activities	(1,610)		(1,751)
Decrease in cash and cash equivalents	(16)		(208)
Cash and cash equivalents, beginning of period	291		419
Cash and cash equivalents, end of period	$	275	$	211


	December 31, 2019						December 31, 2018
	As Originally Reported		Effect of Change		As Adjusted		As Originally Reported		Effect of Change		As Adjusted
Inventories	$	1,935	$	(403)	$	1,532	$	1,677	$	(305)	$	1,372
Total current assets	7,867		(403)		7,464		6,750		(305)		6,445
Other non-current assets, net	1,075		496		1,571		1,006		472		1,478
Total assets	98,880		93		98,973		88,246		167		88,413
Total partners’ capital	21,827		93		21,920		20,559		167		20,726


	Year Ended December 31,				Three Months Ended September 30,		Nine Months Ended September 30,
	2019		2018		2019		2019
As originally reported:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold	$	39,727	$	41,658	$	9,890	$	29,607
Operating income	7,277		5,348		1,830		5,576
Income from continuing operations before income tax expense (benefit)	5,094		3,634		1,215		3,763
Net income	4,899		3,365		1,161		3,549
Net income per limited partner unit	1.37		1.16		0.32		0.98
Comprehensive income	4,930		3,322		1,154		3,551
Comprehensive income attributable to partners	3,623		1,651		825		2,582

Consolidated Statements of Cash Flows
Net income	4,899		3,365		1,161		3,549

Net change in operating assets and liabilities	(518)		289		27		(247)

Effect of change:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold	74		(55)		(26)		35
Operating income	(74)		55		26		(35)
Income from continuing operations before income tax expense (benefit)	(74)		55		26		(35)
Net income	(74)		55		26		(35)
Net income per limited partner unit	(0.03)		0.04		0.01		(0.01)
Comprehensive income	(74)		55		26		(35)
Comprehensive income attributable to partners	(74)		55		26		(35)

Consolidated Statements of Cash Flows
Net income	(74)		55		26		(35)

Net change in operating assets and liabilities	74		(55)		(26)		35

As adjusted:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold	39,801		41,603		9,864		29,642
Operating income	7,203		5,403		1,856		5,541
Income from continuing operations before income tax expense (benefit)	5,020		3,689		1,241		3,728
Net income	4,825		3,420		1,187		3,514
Net income per limited partner unit	1.34		1.20		0.33		0.97
Comprehensive income	4,856		3,377		1,180		3,516
Comprehensive income attributable to partners	3,549		1,706		851		2,547

Consolidated Statements of Cash Flows
Net income	4,825		3,420		1,187		3,514

Net change in operating assets and liabilities	(444)		234		1		(212)


	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		All Other		Total
Balance, December 31, 2019	$	10	$	226	$	483	$	693	$	1,397	$	1,555	$	619	$	184	$	5,167


Impaired	0		(183)		(483)		0		0		0		(619)		(40)		(1,325)
Other	0		0		0		0		0		0		0		(7)		(7)
Balance, March 31, 2020	10		43		0		693		1,397		1,555		0		137		3,835

Other	0		0		0		0		0		0		0		33		33
Balance, June 30, 2020	10		43		0		693		1,397		1,555		0		170		3,868
Impaired	0		(43)		0		0		(1,279)		0		0		(132)		(1,454)
Other	0		0		0		0		(66)		0		0		70		4
Balance, September 30, 2020	$	10	$	0	$	0	$	693	$	52	$	1,555	$	0	$	108	$	2,418


	September 30, 2020		December 31, 2019
Natural gas, NGLs and refined products	$	914	$	833
Crude oil	352		251
Spare parts and other	457		448
Total inventories	$	1,723	$	1,532


	Years Ending December 31,
	2020 (remainder)		2021		2022		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2020	$	1,633	$	5,674	$	5,180	$	27,016	$	39,503


	September 30, 2020		December 31, 2019*
Segment assets:
Intrastate transportation and storage	$	7,215	$	6,648
Interstate transportation and storage	17,341		18,111
Midstream	19,056		20,332
NGL and refined products transportation and services	20,944		19,145
Crude oil transportation and services	19,882		22,933
Investment in Sunoco LP	4,986		5,438
Investment in USAC	3,011		3,730
All other	2,760		2,636
Total segment assets	$	95,195	$	98,973


	September 30, 2020		December 31, 2019
Parent Company Indebtedness:
ET Senior Notes due October 2020	$	—	$	52
ET Senior Notes due March 2023	5		5
ET Senior Notes due January 2024	23		23
ET Senior Notes due June 2027	44		44
Subsidiary Indebtedness:
ETO Senior Notes	37,783		36,118
Transwestern Senior Notes	400		575
Panhandle Senior Notes	235		235
Bakken Senior Notes	2,500		2,500
Sunoco LP Senior Notes and lease-related obligations	2,905		2,935
USAC Senior Notes	1,475		1,475
Credit facilities and commercial paper:
ETO $2.00 billion Term Loan facility due October 2022	2,000		2,000
ETO $5.00 billion Revolving Credit Facility due December 2023 (1)	3,231		4,214
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023	87		162
USAC $1.60 billion Revolving Credit Facility due April 2023	497		403
HFOTCO Tax Exempt Notes due 2050	225		225
SemCAMS Revolver due February 2024	74		92
SemCAMS Revolver Term Loan A due February 2024	253		269
Other long-term debt	3		2
Net unamortized premiums, discounts, and fair value adjustments	(12)		4
Deferred debt issuance costs	(283)		(279)
Total debt	51,445		51,054
Less: current maturities of long-term debt	21		26
Long-term debt, less current maturities	$	51,424	$	51,028