UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~September~~June 30, ~~2019~~2020



☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-31219

Energy Transfer Operating, L.P.

(Exact name of registrant as specified in its charter)



Delaware		73-1493906
(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)

Registrant’s telephone number, including area code: (214) 981-0700

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.

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

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	ETPprC	New York Stock Exchange
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	ETPprD	New York Stock Exchange
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	ETPprE	New York Stock Exchange
~~7.500% Senior Notes due 2020~~	~~ETP 20~~	~~New York Stock Exchange~~
4.250% Senior Notes due 2023	ETP 23	New York Stock Exchange
5.875% Senior Notes due 2024	ETP 24	New York Stock Exchange
5.500% Senior Notes due 2027	ETP 27	New York Stock Exchange

FORM 10-Q

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

Table of Contents

~~Forward-Looking Statements~~Definitions

~~Certain matters discussed in this report, excluding historical information, as well as some statements by~~References to the “Partnership” or “ETO” refer to Energy Transfer Operating, L.P. ~~(the “Partnership” or “ETO”) in periodic press releases and some oral statements of~~In addition, the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 filed with the Securities and Exchange Commission on February 22, 2019.

~~Definitions~~

~~The~~ following is a list of certain acronyms and terms ~~generally~~ used ~~in the energy industry and~~ throughout this document:



	/d		per day

	~~AmeriGas~~		~~AmeriGas Partners, L.P.~~

	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 used

	~~CDM~~		~~CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively~~

	Citrus		Citrus, LLC ~~which owns 100% of FGT~~

	DOJ		United States Department of Justice

	EPA		United States Environmental Protection Agency

	ET		Energy Transfer LP, ~~a publicly traded partnership and~~ the ~~owner~~parent company of ~~ETP LLC~~

	~~ETC Sunoco~~		~~ETC Sunoco Holdings LLC (formerly Sunoco, Inc.)~~ETO

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

	ETP LLC		Energy Transfer Partners, L.L.C., the general partner of ETP GP

	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

	~~IDRs~~HFOTCO		~~incentive distribution rights~~Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal

	Lake Charles LNG		Lake Charles LNG Company, LLC, ~~(previously named Trunkline LNG Company, LLC)~~a wholly-owned subsidiary of ETO

	LIBOR		London Interbank Offered Rate

	MBbls		thousand barrels

	MEP		Midcontinent Express Pipeline LLC

	MTBE		methyl tertiary butyl ether

~~Table of Contents~~



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

	NYMEX		New York Mercantile Exchange

	OSHA		federal Occupational Safety and Health Act

	OTC		over-the-counter

	Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries, wholly-owned by ETO

	PES		Philadelphia Energy Solutions Refining and Marketing LLC, non-controlling interest owned by ETO

	Preferred Unitholders		Unitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units and Series EG Preferred Units, collectively

	Regency		Regency Energy Partners LP,

	~~RIGS~~		~~Regency Intrastate Gas System~~ a wholly-owned subsidiary of ETO

	Rover		Rover Pipeline LLC, a less than wholly-owned subsidiary of ETO

	SEC		Securities and Exchange Commission

	SemCAMS		SemCAMS Midstream ULC, a less than wholly-owned subsidiary of ETO

	SemGroup		SemGroup, ~~Corporation~~LLC (formerly SemGroup Corporation)

Table of Contents




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

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

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

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

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

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

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

	SPLP		Sunoco Pipeline L.P., a wholly-owned subsidiary of ETO

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

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

	~~Southwest Gas~~		~~Pan Gas Storage LLC (d.b.a. Southwest Gas Storage Company)~~

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

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

	~~UGI~~		~~UGI Corporation~~

	USAC		USA Compression Partners, LP, a wholly-owned subsidiary of ETO

	USAC Preferred Units		USAC Series A Preferred Units
	White Cliffs		White Cliffs Pipeline

iii

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)


	September 30, 2019			December 31, 2018			June 30, 2020			December 31, 2019*
ASSETS
Current assets:
Cash and cash equivalents	$	207		$	418		$	152		$	288
Accounts receivable, net	4,368			4,009			2,955			5,038
Accounts receivable from related companies	224			176			139			167
Inventories	1,814			1,677			1,593			1,532
Income taxes receivable	109			73			68			147
Derivative assets	56			111			14			23
Other current assets	377			356			245			291
Total current assets	7,155			6,820			5,166			7,486

Property, plant and equipment	83,537			79,280			91,774			89,294
Accumulated depreciation and depletion	(14,667		)	(12,625		)	(17,125		)	(15,398		)
	68,870			66,655			74,649			73,896

Advances to and investments in unconsolidated affiliates	2,987			2,636			3,306			3,454
Lease right-of-use assets, net	889			—			1,112			964
Other non-current assets, net	1,089			1,006			1,511			1,572
Notes receivable from related company	3,606			440			2,865			3,603
Intangible assets, net	5,781			6,000			6,007			6,154
Goodwill	4,870			4,885			3,868			5,167
Total assets	$	95,247		$	88,442		$	98,484		$	102,296

*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)


	September 30, 2019			December 31, 2018			June 30, 2020			December 31, 2019*
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,519		$	3,491		$	2,138		$	4,119
Accounts payable to related companies	23			119			36			31
Derivative liabilities	181			185			24			147
Operating lease current liabilities	57			—			54			60
Accrued and other current liabilities	3,228			2,847			2,730			3,339
Current maturities of long-term debt	14			2,655			34			25
Total current liabilities	7,022			9,297			5,016			7,721

Long-term debt, less current maturities	46,716			37,853			51,179			50,905
Non-current derivative liabilities	360			104			577			273
Non-current operating lease liabilities	807			—			903			901
Deferred income taxes	3,094			2,884			3,277			3,171
Other non-current liabilities	1,138			1,184			1,216			1,161
	��
Commitments and contingencies
Redeemable noncontrolling interests	499			499			750			739

Equity:
Limited Partners:
Preferred Unitholders	3,151			2,388			4,764			3,174
Common Unitholders	24,526			26,372			22,510			24,226
Accumulated other comprehensive loss	(40		)	(42		)	(21		)	(18		)
Total partners’ capital	27,637			28,718			27,253			27,382
Noncontrolling interests	7,974			7,903			8,313			8,018
Predecessor equity							—			2,025
Total equity	35,611			36,621			35,566			37,425
Total liabilities and equity	$	95,247		$	88,442		$	98,484		$	102,296

*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)

(unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2020			2019*			2020			2019*
REVENUES:
Refined product sales	$	4,311		$	4,777		$	12,514		$	12,980		$	2,000		$	4,477		$	5,232		$	8,203
Crude sales	3,971			3,844			11,842			11,344			1,329			4,346			4,872			7,871
NGL sales	1,723			2,870			6,121			7,461			1,254			1,996			2,943			4,398
Gathering, transportation and other fees	2,466			1,781			6,768			4,878			2,137			2,035			4,522			4,302
Natural gas sales	822			1,026			2,549			3,112			514			763			1,102			1,727
Other	202			216			699			739			104			260			294			497
Total revenues	13,495			14,514			40,493			40,514			7,338			13,877			18,965			26,998
COSTS AND EXPENSES:
Cost of products sold	9,890			11,093			29,607			31,681			4,117			10,301			12,408			19,778
Operating expenses	806			784			2,406			2,280			770			792			1,649			1,600
Depreciation, depletion and amortization	782			747			2,334			2,100			934			781			1,799			1,552
Selling, general and administrative	171			175			495			495			171			175			373			324
Impairment losses	12			—			62			—			4			—			1,329			50
Total costs and expenses	11,661			12,799			34,904			36,556			5,996			12,049			17,558			23,304
OPERATING INCOME	1,834			1,715			5,589			3,958			1,342			1,828			1,407			3,694
OTHER INCOME (EXPENSE):
Interest expense, net of capitalized interest	(575		)	(446		)	(1,680		)	(1,246		)
Interest expense, net of interest capitalized													(578		)	(578		)	(1,178		)	(1,105		)
Equity in earnings of unconsolidated affiliates	82			87			224			258			85			77			78			142
Losses on extinguishments of debt	—			—			(2		)	(109		)	—			—			(59		)	(2		)
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Losses on interest rate derivatives													(3		)	(122		)	(332		)	(196		)
Other, net	113			40			242			96			(29		)	112			16			129
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	1,279			1,441			4,002			3,074
Income tax expense (benefit) from continuing operations	55			(52		)	216			7
INCOME FROM CONTINUING OPERATIONS	1,224			1,493			3,786			3,067
Loss from discontinued operations, net of income taxes	—			(2		)	—			(265		)
NET INCOME	1,224			1,491			3,786			2,802
INCOME (LOSS) BEFORE INCOME TAX EXPENSE													817			1,317			(68		)	2,662
Income tax expense													98			35			127			161
NET INCOME (LOSS)													719			1,282			(195		)	2,501
Less: Net income attributable to noncontrolling interests	261			223			783			557			225			266			25			522
Less: Net income attributable to redeemable noncontrolling interests	12			—			38			—			13			13			25			26
Less: Net income (loss) attributable to predecessor equity	—			133			—			(37		)
NET INCOME ATTRIBUTABLE TO PARTNERS	$	951		$	1,135		$	2,965		$	2,282
Less: Net loss attributable to predecessor equity													—			—			(6		)	—
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS													$	481		$	1,003		$	(239	)	$	1,953

*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

(unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
Net income $ 1,224
$ 1,491
$ 3,786
$ 2,802
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities —
2
8
—
Actuarial gain (loss) related to pension and other postretirement benefit plans (3 ) —
7
(2 )
Change in other comprehensive income from unconsolidated affiliates (4 ) 2
(13 ) 9
(7 ) 4
2
7
Comprehensive income 1,217
1,495
3,788
2,809
Less: Comprehensive income attributable to noncontrolling interests 261
223
783
557
Less: Comprehensive income attributable to redeemable noncontrolling interests 12
—
38
—
Less: Comprehensive income (loss) attributable to predecessor equity —
133
—
(37 )
Comprehensive income attributable to partners $ 944
$ 1,139
$ 2,967
$ 2,289



	Three Months Ended June 30,					Six Months Ended June 30,
	2020		2019*			2020			2019*
Net income (loss)	$	719	$	1,282		$	(195	)	$	2,501
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	9		3			—			8
Actuarial gain related to pension and other postretirement benefit plans	8		3			14			10
Foreign currency translation adjustments	30		—			30			—
Change in other comprehensive loss from unconsolidated affiliates	—		(5		)	(16		)	(9		)
	47		1			28			9
Comprehensive income (loss)	766		1,283			(167		)	2,510
Less: Comprehensive income attributable to noncontrolling interests	225		266			25			522
Less: Comprehensive income attributable to redeemable noncontrolling interests	13		13			25			26
Less: Comprehensive loss attributable to predecessor equity	—		—			(6		)	—
Comprehensive income (loss) attributable to partners	$	528	$	1,004		$	(211	)	$	1,962

*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

(unaudited)


	Limited Partners															Limited Partners
	Preferred Unitholders			Common Unitholders			AOCI			Non-controlling Interests			Total			Preferred Unitholders			Common Unitholders			AOCI			Noncontrolling Interests			Predecessor Equity			Total
Balance, December 31, 2018	$	2,388		$	26,372		$	(42	)	$	7,903		$	36,621
Distributions to partners	(64		)	(1,450		)	—			—			(1,514		)
Distributions to noncontrolling interests	—			—			—			(361		)	(361		)
Capital contributions from noncontrolling interests	—			—			—			140			140
Sale of noncontrolling interest in subsidiary	—			—			—			93			93
Other comprehensive income, net of tax	—			—			8			—			8
Other, net	—			15			—			13			28
Net income, excluding amounts attributable to redeemable noncontrolling interests	40			972			—			256			1,268
Balance, March 31, 2019	2,364			25,909			(34		)	8,044			36,283
Balance, December 31, 2019*																$	3,174		$	24,226		$	(18	)	$	8,018		$	2,025		$	37,425
Distributions to partners	(18		)	(1,625		)	—			—			(1,643		)	(80		)	(2,550		)	—			—			—			(2,630		)
Distributions to noncontrolling interests	—			—			—			(370		)	(370		)	—			—			—			(340		)	(25		)	(365		)
Units issued for cash	780			—			—			—			780			1,580			—			—			—			—			1,580
Capital contributions from noncontrolling interests	—			—			—			66			66			—			—			—			66			30			96
SemGroup contribution (See Note 2)																—			1,840			(2		)	333			(2,171		)	—
Other comprehensive loss, net of tax																—			—			(19		)	—			(38		)	(57		)
Other, net																(3		)	(8		)	—			3			(10		)	(18		)
Net income (loss), excluding amounts attributable to redeemable noncontrolling interests																77			(797		)	—			(200		)	(6		)	(926		)
Balance, March 31, 2020*																4,748			22,711			(39		)	7,880			(195		)	35,105
Distributions to partners																(67		)	—			—			—			—			(67		)
Distributions to noncontrolling interests																—			—			—			(340		)	—			(340		)
Capital contributions from noncontrolling interests																—			—			—			82			—			82
SemGroup contribution (See Note 2)																—			(630		)	(20		)	455			195			—
Other comprehensive income, net of tax	—			—			1			—			1			—			—			38			9			—			47
Other, net	(1		)	(36		)	—			—			(37		)	(1		)	32			—			2			—			33
Net income, excluding amounts attributable to redeemable noncontrolling interests	53			949			—			266			1,268			84			397			—			225			—			706
Balance, June 30, 2019	3,178			25,197			(33		)	8,006			36,348
Distributions to partners	(82		)	(1,562		)	—			—			(1,644		)
Distributions to noncontrolling interests	—			—			—			(374		)	(374		)
Capital contributions from noncontrolling interests	—			—			—			72			72
Other comprehensive loss, net of tax	—			—			(7		)	—			(7		)
Other, net	—			(5		)	—			9			4
Net income, excluding amounts attributable to redeemable noncontrolling interests	55			896			—			261			1,212
Balance, September 30, 2019	$	3,151		$	24,526		$	(40	)	$	7,974		$	35,611
Balance, June 30, 2020																$	4,764		$	22,510		$	(21	)	$	8,313		$	—		$	35,566

*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

(unaudited)


	Limited Partners																					Limited Partners
	Preferred Unitholders			Common Unitholders			General Partner			AOCI			Non-controlling Interests			Predecessor Equity			Total			Preferred Unitholders			Common Unitholders			AOCI			Noncontrolling Interests			Total
Balance, December 31, 2017	$	1,491		$	26,531		$	244		$	3		$	5,882		$	2,816		$	36,967
Balance, December 31, 2018*																						$	2,388		$	26,539		$	(42	)	$	7,903		$	36,788
Distributions to partners	(24		)	(657		)	(264		)	—			—			—			(945		)	(64		)	(1,450		)	—			—			(1,514		)
Distributions to noncontrolling interests	—			—			—			—			(183		)	(70		)	(253		)	—			—			—			(361		)	(361		)
Units issued for cash	—			20			—			—			—			—			20
Repurchases of common units	—			(24		)	—			—			—			—			(24		)
Subsidiary repurchases of common units	—			—			—			—			—			(300		)	(300		)
Capital contributions from noncontrolling interests	—			—			—			—			229			—			229			—			—			—			140			140
Cumulative effect adjustment due to change in accounting principle	—			—			—			—			—			(54		)	(54		)
Sale of noncontrolling interest in subsidiary																						—			—			—			93			93
Other comprehensive income, net of tax	—			—			—			1			—			—			1			—			—			8			—			8
Other, net	(2		)	(16		)	(17		)	(2		)	(6		)	1			(42		)	—			15			—			13			28
Net income (loss)	24			289			402			—			164			(302		)	577
Balance, March 31, 2018	1,489			26,143			365			2			6,086			2,091			36,176
Distributions to partners	—			(658		)	(408		)	—			—			—			(1,066		)
Distributions to noncontrolling interests	—			—			—			—			(176		)	(101		)	(277		)
Units issued for cash	436			19			—			—			—			—			455
Capital contributions from noncontrolling interests	—			—			—			—			89			—			89
Acquisition of USAC	—			—			—			—			—			832			832
Deemed contribution	—			—			—			—			—			248			248
Other comprehensive income, net of tax	—			—			—			2			—			—			2
Other, net	1			42			—			—			2			10			55
Net income	30			—			402			—			170			132			734
Balance, June 30, 2018	1,956			25,546			359			4			6,171			3,212			37,248
Net income, excluding amounts attributable to redeemable noncontrolling interest																						40			910			—			256			1,206
Balance, March 31, 2019*																						2,364			26,014			(34		)	8,044			36,388
Distributions to partners	(57		)	(660		)	(408		)	—			—			—			(1,125		)	(18		)	(1,625		)	—			—			(1,643		)
Distributions to noncontrolling interests	—			—			—			—			(177		)	(101		)	(278		)	—			—			—			(370		)	(370		)
Units issued for cash	431			19			—			—			—			—			450			780			—			—			—			780
Capital contributions from noncontrolling interests	—			—			—			—			120			—			120			—			—			—			66			66
Other comprehensive income, net of tax	—			—			—			4			—			—			4			—			—			1			—			1
Other, net	(2		)	15			—			—			(3		)	5			15			(1		)	(36		)	—			—			(37		)
Net income, excluding amounts attributable to redeemable noncontrolling interests	38			708			389			—			223			107			1,465
Balance, September 30, 2018	$	2,366		$	25,628		$	340		$	8		$	6,334		$	3,223		$	37,899
Net income, excluding amounts attributable to redeemable noncontrolling interest																						53			950			—			266			1,269
Balance, June 30, 2019*																						$	3,178		$	25,303		$	(33	)	$	8,006		$	36,454

*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)


	Nine Months Ended September 30,						Six Months Ended June 30,
	2019			2018			2020			2019*
OPERATING ACTIVITIES
Net income	$	3,786		$	2,802
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	—			265
OPERATING ACTIVITIES:
Net income (loss)							$	(195	)	$	2,501
Reconciliation of net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	2,334			2,100			1,799			1,552
Deferred income taxes	193			2			126			140
Inventory valuation adjustments	(71		)	(50		)	137			(97		)
Non-cash compensation expense	85			82			63			58
Impairment losses	62			—			1,329			50
Losses on extinguishments of debt	2			109			59			2
Distributions on unvested awards	(5		)	(36		)	(3		)	(3		)
Equity in earnings of unconsolidated affiliates	(224		)	(258		)	(78		)	(142		)
Distributions from unconsolidated affiliates	254			229			125			170
Other non-cash	(29		)	(93		)	(12		)	(24		)
Net change in operating assets and liabilities, net of effects of acquisitions	(325		)	358			27			(187		)
Net cash provided by operating activities	6,062			5,510			3,377			4,020
INVESTING ACTIVITIES
INVESTING ACTIVITIES:
Cash proceeds from sale of noncontrolling interest in subsidiary	93			—			—			93
Cash proceeds from USAC acquisition, net of cash received	—			711
Cash paid for all other acquisitions, net of cash received	(7		)	(233		)	—			(7		)
Capital expenditures, excluding allowance for equity funds used during construction	(4,181		)	(5,175		)	(2,892		)	(2,818		)
Contributions in aid of construction costs	63			95			47			41
Contributions to unconsolidated affiliates	(481		)	(13		)	(16		)	(254		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	40			62			97			21
Proceeds from the sale of other assets	55			40			6			22
Other	(5		)	—			(5		)	(40		)
Net cash used in investing activities	(4,423		)	(4,513		)	(2,763		)	(2,942		)
FINANCING ACTIVITIES
FINANCING ACTIVITIES:
Proceeds from borrowings	18,125			21,713			16,975			16,463
Repayments of debt	(16,027		)	(22,620		)	(16,717		)	(14,705		)
Cash received from/paid to related company	1,018			(129		)
Common units issued for cash	—			57
Cash received from related company							676			180
Preferred units issued for cash	780			868			1,580			780
Redeemable noncontrolling interests issued for cash	—			465
Capital contributions from noncontrolling interests	278			438			148			206
Predecessor capital contributions from noncontrolling interests							30			—
Distributions to partners	(4,801		)	(3,136		)	(2,697		)	(3,157		)
Predecessor distributions to partners	—			(280		)
Distributions to noncontrolling interests	(1,105		)	(536		)	(680		)	(731		)
Distributions to redeemable noncontrolling interest	—			(12		)
Repurchases of common units	—			(24		)
Subsidiary repurchases of common units	—			(300		)
Predecessor distributions to noncontrolling interests							(25		)	—
Debt issuance costs	(114		)	(188		)	(50		)	(87		)
Other	(4		)	11			10			(1		)
Net cash used in financing activities	(1,850		)	(3,673		)	(750		)	(1,052		)
DISCONTINUED OPERATIONS
Operating activities	—			(480		)
Investing activities	—			3,207
Changes in cash included in current assets held for sale	—			11
Net increase in cash and cash equivalents of discontinued operations	—			2,738
Increase in cash and cash equivalents	(211		)	62
Increase (decrease) in cash and cash equivalents							(136		)	26
Cash and cash equivalents, beginning of period	418			335			288			418
Cash and cash equivalents, end of period	$	207		$	397		$	152		$	444

*As adjusted. See Note 1.

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts are in millions)

(unaudited)


1.	ORGANIZATION AND BASIS OF PRESENTATION

Organization

The consolidated financial statements presented herein include Energy Transfer Operating, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETO”).

Energy Transfer Operating, L.P. is a consolidated subsidiary of Energy Transfer LP. In ~~October 2018, we~~December 2019, ET completed the ~~merger~~acquisition of ~~ETO with a wholly-owned subsidiary~~SemGroup. During the first and second quarters of 2020, ET ~~in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, ETO unitholders (other than ET~~contributed SemGroup and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. Following the closing of the Energy Transfer Merger, Energy Transfer Partners, L.P. was renamed Energy Transfer Operating, L.P. In addition, Energy Transfer Equity, L.P. was renamed Energy Transfer LP, and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on October 19, 2018.

~~Immediately prior to the closing of the Energy Transfer Merger, the following also occurred:~~

~~the IDRs in ETO were converted into 1,168,205,710 ETO common units;~~

~~the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued 18,448,341 ETO common units to ETP GP;~~

~~ET contributed its 2,263,158 Sunoco LP common units~~former subsidiaries to ETO ~~in exchange~~through sale and contribution transactions. The contribution transactions were accounted for 2,874,275 ETO common units and 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;

ET contributed its 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and

ET contributed its 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETO in exchange for 37,557,815 ETO common units.

~~The Energy Transfer Merger was a combination~~as reorganizations of entities under common control; therefore, ~~Sunoco LP, Lake Charles LNG and USAC’s~~the contributed entities’ assets and liabilities were not ~~adjusted.~~adjusted as of the contribution date. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation beginning ~~January 1, 2018~~December 5, 2019 for ~~Sunoco LP and Lake Charles LNG and Other and April 2, 2018 for USAC~~SemGroup assets contributed (the date ET acquired ~~USAC)~~SemGroup). Predecessor equity included onin the consolidated financial statements represents ~~Sunoco LP, Lake Charles LNG and Other and USAC’s~~the equity of contributed entities prior to the ~~Energy Transfer Merger.~~contribution transactions.

Our consolidated 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

•all other.

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 of Energy Transfer Operating, L.P. for the year ended December 31, ~~2018,~~2019, included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February ~~22, 2019.~~21, 2020. In the opinion of the Partnership’s management,

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such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

The consolidated financial statements of the Partnership presented herein include the results of operations of our controlled subsidiaries, including Sunoco LP and USAC.

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

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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 impacts of this accounting policy change on the Partnership’s net income for the six months ended June 30, 2020 was approximately $265 million. 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	7,889		(403		)	7,486		6,820		(305		)	6,515
Other non-current assets, net	1,076		496			1,572		1,006		472			1,478
Total assets	102,203		93			102,296		88,442		167			88,609
Total partners’ capital	27,289		93			27,382		28,718		167			28,885

* Amounts reflect the retrospective consolidation of the SemGroup entities discussed above.

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



	Year Ended December 31,						Three Months Ended June 30,			Six Months Ended June 30,
	2019			2018			2019			2019
As originally reported:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold	$	39,603		$	41,658		$	10,302		$	19,717
Operating income	7,285			5,402			1,827			3,755
Income from continuing operations before income tax expense	5,386			4,044			1,316			2,723
Net income	5,186			3,774			1,281			2,562
Comprehensive income	5,210			3,731			1,282			2,571
Comprehensive income attributable to partners	4,108			2,982			1,003			2,023

Consolidated Statements of Cash Flows
Net income	5,186			3,774			1,281			2,562
Net change in operating assets and liabilities	(479		)	117			151			(248		)

Effect of change:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold	74			(55		)	(1		)	61
Operating income	(74		)	55			1			(61		)
Income from continuing operations before income tax expense	(74		)	55			1			(61		)
Net income	(74		)	55			1			(61		)
Comprehensive income	(74		)	55			1			(61		)
Comprehensive income attributable to partners	(74		)	55			1			(61		)

Consolidated Statements of Cash Flows
Net income	(74		)	55			1			(61		)
Net change in operating assets and liabilities	74			(55		)	(1		)	61

As adjusted:
Consolidated Statements of Operations and Comprehensive Income
Cost of products sold	39,677			41,603			10,301			19,778
Operating income	7,211			5,457			1,828			3,694
Income from continuing operations before income tax expense	5,312			4,099			1,317			2,662
Net income	5,112			3,829			1,282			2,501
Comprehensive income	5,136			3,786			1,283			2,510
Comprehensive income attributable to partners	4,034			3,037			1,004			1,962

Consolidated Statements of Cash Flows
Net income	5,112			3,829			1,282			2,501
Net change in operating assets and liabilities	(405		)	62			150			(187		)

Use of Estimates

The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although

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these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

~~Change in~~Recent Accounting ~~Policy~~

~~Adoption of Lease Accounting Standard~~Pronouncements

~~In February 2016,~~Effective January 1, 2020, the ~~Financial Accounting Standards Board (“FASB”) issued~~Partnership adopted Accounting Standards Update (“ASU”) ~~No. 2016-02,~~ ~~Leases~~2016-13 “Financial Instruments - Credit Losses (Topic ~~842), which has amended~~326) Measurement of Credit Losses on Financial Instruments.” ASU 2016-13 requires an entity to utilize a new impairment model known as the ~~FASB Accounting Standards Codification~~current expected credit loss (“~~ASC”~~CECL”) model to estimate its lifetime “expected credit loss” and ~~introduced Topic 842, Leases. On January 1, 2019,~~record an allowance that, when deducted from the amortized cost basis of the financial asset, presents the net amount expected to be collected on the financial asset. The CECL model is expected to result 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 ~~has adopted ASC Topic 842 (“Topic 842”), which is effective~~and its subsidiaries recorded an aggregate $16 million of current expected credit losses for ~~interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on~~ the ~~balance sheet for all leases with a term~~six months ended June 30, 2020.

Goodwill

During the first quarter of ~~more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard.~~

~~To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment~~2020, due to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoptionimpacts of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assetsCOVID-19 pandemic, the decline in commodity prices and ~~lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support~~ the ~~on-going reporting requirements under the new standard.~~

To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population.

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~~Cumulative-effect adjustments made to the opening balance sheet at January 1, 2019 were as follows:~~

Balance at December 31, 2018, as previously reported Adjustments due to Topic 842 (Leases) Balance at January 1, 2019
Assets:
Property, plant and equipment, net $ 66,655
$ (1 ) $ 66,654
Lease right-of-use assets, net —
889
889
Liabilities:
Operating lease current liabilities $ —
$ 71
$ 71
Accrued and other current liabilities 2,847
(1 ) 2,846
Current maturities of long-term debt 2,655
1
2,656
Long-term debt, less current maturities 37,853
6
37,859
Non-current operating lease liabilities —
823
823
Other non-current liabilities 1,184
(12 ) 1,172

~~Additional disclosures related to lease accounting are included in Note 12.~~

~~Goodwill~~

~~The Partnership’s interstate transportation and storage segment owns Southwest Gas which owns and operates natural gas storage assets. Due to a decrease~~decreases in the ~~demand for storage on these assets, the Partnership performed an~~Partnership’s market capitalization, we determined that interim impairment ~~test~~testing should be performed on certain reporting units. We performed the ~~assets of Southwest Gas during the three months ended September 30, 2019.~~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 ~~$12~~$483 million related to ~~Southwest Gas,~~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.~~flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of $619 million during the three months ended March 31, 2020, which is included in the Partnership’s consolidated results of operations. No other impairments of the Partnership’s ~~other assets~~goodwill were identified. ~~The~~

In connection with aforementioned impairments, the Partnership ~~estimated~~determined the fair value of ~~Southwest Gas by~~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, ~~a discount rate~~revenue growth rates, operating margins, weighted average costs of capital and ~~a terminal value.~~ future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. 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.


2.	~~ACQUISITIONS, DIVESTURES AND RELATED TRANSACTIONS~~

~~Sunoco LP Retail Store and Real Estate Sales~~

~~On January 23, 2018, Sunoco LP completed~~Of the ~~disposition~~$3.87 billion of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-Eleven Transaction”). As a result of the 7-Eleven Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties. Also, the related accounts receivable from such sales are no longer eliminated fromgoodwill on the Partnership’s consolidated balance ~~sheets and are reported as accounts receivable.~~

~~In connection with the 7-Eleven Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated~~sheet as of ~~January 23, 2018, as amended (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists of a 15-year take-or-pay fuel supply arrangement. For~~June 30, 2020, approximately $1.2 billion is recorded in reporting units for which the ~~period from January 1, 2018 through January 22, 2018, Sunoco LP recorded sales to~~estimated fair value exceeded the ~~sites~~carrying value by less than 20% in the most recent quantitative test. Management believes that were subsequently sold to 7-Eleven of $199 million, which were eliminated in consolidation. Sunoco LP received payments on trade receivables from 7-Eleven of $1.0 billion and $2.9 billion for the three and nine months ended September 30, 2019, respectively, and $1.0 billion and $2.6 billion for the three and nine months ended September 30, 2018, respectively, subsequent to the closingall of the ~~sale.~~$1.2 billion is at significant risk of impairment, if commodity prices and/or overall market demand remains low.

~~The Partnership has concluded that it meets~~Changes in the ~~accounting requirements for reporting the financial position, results~~carrying amounts of ~~operations and cash flows of Sunoco LP’s retail divestment~~goodwill were as ~~discontinued operations.~~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	—		(183		)	(483		)	—		—		—		(619		)	(40		)	(1,325		)
Other	—		—			—			—		—		—		—			(7		)	(7		)
Balance, March 31, 2020	10		43			—			693		1,397		1,555		—			137			3,835
Other	—		—			—			—		—		—		—			33			33
Balance, June 30, 2020	$	10	$	43		$	—		$	693	$	1,397	$	1,555	$	—		$	170		$	3,868

1011

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2.	ACQUISITIONS AND RELATED TRANSACTIONS

~~There were no results~~ET Contribution of operations associated with discontinued operations for the three and nine months ended September 30, 2019. The results of operations associated with discontinued operations for the three and nine months ended ended September 30, 2018 were as follows:SemGroup Assets to ETO

As discussed in Note 1, former SemGroup subsidiaries were transferred from ET to ETO during the first and second quarter of 2020. The following table represents the fair value, as of December 5, 2019, of the SemGroup assets and liabilities transferred from ET to ETO:

Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
REVENUES $ —
$ 349

COSTS AND EXPENSES
Cost of products sold —
305
Operating expenses —
61
Selling, general and administrative —
7
Total costs and expenses —
373
OPERATING LOSS —
(24 )
Interest expense, net —
(2 )
Loss on extinguishment of debt and other —
(20 )
Other, net —
(61 )
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE —
(107 )
Income tax expense 2
158
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ (2 ) $ (265 )



	At December 5, 2019
Total current assets	$	794
Property, plant and equipment	3,891
Other non-current assets	617
Goodwill	295
Intangible assets	460
Total assets	6,057

Total current liabilities	629
Long-term debt, less current maturities ⁽¹⁾	2,576
Other non-current liabilities	197
SemCAMS Preferred shares	241
Total liabilities	3,643

Noncontrolling interest	822

Partners’ capital	1,592
Total liabilities and partners’ capital	$	6,057

⁽¹⁾ Long-term debt at December 5, 2019 includes SemGroup senior notes with an aggregate principal amount of $1.375 billion and SemGroup subsidiary debt of $593 million, all of which was redeemed in December 2019, subsequent to the closing of ET’s acquisition of SemGroup, using proceeds from an intercompany promissory note from ETO.


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~~June 30, ~~2019~~2020 or December 31, ~~2018.~~2019.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:


	Nine Months Ended September 30,						Six Months Ended June 30,
	2019			2018			2020			2019
Accounts receivable	$	(353	)	$	152		$	2,084		$	(340	)
Accounts receivable from related companies	(30		)	261			118			7
Inventories	(66		)	78			(180		)	28
Other current assets	(14		)	(19		)	150			37
Other non-current assets, net	(182		)	(154		)	(159		)	(43		)
Accounts payable	27			(232		)	(2,108		)	201
Accounts payable to related companies	(105		)	(227		)	12			(109		)
Accrued and other current liabilities	194			406			(122		)	(21		)
Other non-current liabilities	(103		)	25			42			(87		)
Derivative assets and liabilities, net	307			68			190			140
Net change in operating assets and liabilities, net of effects of acquisitions	$	(325	)	$	358		$	27		$	(187	)

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Non-cash activities are as follows:


	Nine Months Ended September 30,					Six Months Ended June 30,
	2019		2018			2020		2019
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	1,202	$	1,059		$	742	$	714
Lease assets obtained in exchange for new lease liabilities	73		—			125		15
Losses from subsidiary common unit transactions	—		(125		)


4.	INVENTORIES

As further discussed in Note 1, the Partnership elected to change 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, the Partnership’s inventory balance for the prior period has been retrospectively adjusted.

Inventories consisted of the following:


	September 30, 2019		December 31, 2018		June 30, 2020		December 31, 2019
Natural gas, NGLs and refined products	$	900	$	833	$	774	$	833
Crude oil	510		506		367		251
Spare parts and other	404		338		452		448
Total inventories	$	1,814	$	1,677	$	1,593	$	1,532

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 June 30, 2020 and December 31, 2019, the carrying value of Sunoco LP’s fuel inventory included lower of cost or market reserves of $372 million and $229 million, respectively, and the inventory carrying value equaled or exceeded its replacement cost. For the three and six months ended June 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.

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5.	FAIR VALUE MEASURES

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2019 was $50.66 billion and $46.73 billion, respectively. As of December 31, 2018, the aggregate fair value and carrying amount of our consolidated debt obligations was $39.54 billion and $40.51 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

We have commodity derivatives and interest rate derivatives 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~~six months ended ~~September~~June 30, ~~2019,~~2020, 0 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~~June 30, ~~2019~~2020 and December 31, ~~2018~~2019 based on inputs used to derive their fair values:


				Fair Value Measurements at September 30, 2019									Fair Value Measurements at June 30, 2020
	Fair Value Total			Level 1			Level 2			Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	27		$	27		$	—		$	112		$	112		$	—
Swing Swaps IFERC	5			—			5			2			—			2
Fixed Swaps/Futures	44			44			—			93			93			—
Forward Physical Contracts	5			—			5			7			—			7
Power:
Forwards	21			—			21			21			—			21
Futures	4			4			—			3			3			—
Options – Puts										1			1			—
Options – Calls										1			1			—
NGLs – Forwards/Swaps	529			529			—			208			208			—
Refined Products – Futures	1			1			—			4			4			—
Crude – Forwards/Swaps	43			43			—			3			3			—
Total commodity derivatives	679			648			31			455			425			30
Other non-current assets	29			19			10			29			19			10
Total assets	$	708		$	667		$	41		$	484		$	444		$	40
Liabilities:
Interest rate derivatives	$	(528	)	$	—		$	(528	)	$	(577	)	$	—		$	(577	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(54		)	(54		)	—			(83		)	(83		)	—
Swing Swaps IFERC	(9		)	—			(9		)	(5		)	—			(5		)
Fixed Swaps/Futures	(29		)	(29		)	—			(117		)	(117		)	—
Forward Physical Contracts	(2		)	—			(2		)	(1		)	—			(1		)
Power:
Forwards	(14		)	—			(14		)	(17		)	—			(17		)
Futures	(5		)	(5		)	—			(3		)	(3		)	—
Options – Calls	(1		)	(1		)	—
NGLs – Forwards/Swaps	(479		)	(479		)	—			(218		)	(218		)	—
Refined Products – Futures	(3		)	(3		)	—			(21		)	(21		)	—
Crude – Forwards/Swaps	(1		)	(1		)	—			(1		)	(1		)	—
Total commodity derivatives	(597		)	(572		)	(25		)	(466		)	(443		)	(23		)
Total liabilities	$	(1,125	)	$	(572	)	$	(553	)	$	(1,043	)	$	(443	)	$	(600	)

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				Fair Value Measurements at December 31, 2018									Fair Value Measurements at December 31, 2019
	Fair Value Total			Level 1			Level 2			Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	42		$	42		$	—		$	17		$	17		$	—
Swing Swaps IFERC	52			8			44			1			—			1
Fixed Swaps/Futures	97			97			—			65			65			—
Forward Physical Contracts	20			—			20			3			—			3
Power:
Forwards	48			—			48			11			—			11
Futures	1			1			—			4			4			—
Options – Puts										1			1			—
Options – Calls	1			1			—			1			1			—
NGLs – Forwards/Swaps	291			291			—			260			260			—
Refined Products – Futures	7			7			—			8			8			—
Crude – Forwards/Swaps	1			1			—			13			13			—
Total commodity derivatives	560			448			112			384			369			15
Other non-current assets	26			17			9			31			20			11
Total assets	$	586		$	465		$	121		$	415		$	389		$	26
Liabilities:
Interest rate derivatives	$	(163	)	$	—		$	(163	)	$	(399	)	$	—		$	(399	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(91		)	(91		)	—			(49		)	(49		)	—
Swing Swaps IFERC	(40		)	—			(40		)	(1		)	—			(1		)
Fixed Swaps/Futures	(88		)	(88		)	—			(43		)	(43		)	—
Forward Physical Contracts	(21		)	—			(21		)
Power:
Forwards	(42		)	—			(42		)	(5		)	—			(5		)
Futures	(1		)	(1		)	—			(3		)	(3		)	—
NGLs – Forwards/Swaps	(224		)	(224		)	—			(278		)	(278		)	—
Refined Products – Futures	(15		)	(15		)	—			(10		)	(10		)	—
Crude – Forwards/Swaps	(61		)	(61		)	—
Total commodity derivatives	(583		)	(480		)	(103		)	(389		)	(383		)	(6		)
Total liabilities	$	(746	)	$	(480	)	$	(266	)	$	(788	)	$	(383	)	$	(405	)

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 June 30, 2020 was $52.92 billion and $51.21 billion, respectively. As of December 31, 2019, the aggregate fair value and carrying amount of our consolidated debt obligations was $54.66 billion and $50.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.


6.	DEBT OBLIGATIONS

Notes and Debentures

~~ET-ETO~~ETO January 2020 Senior Notes ~~Exchange~~

In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO (the “ET-ETO senior notes exchange”). Approximately 97% of ET’s outstanding senior notes were tenderedOffering and ~~accepted, and substantially all the exchanges settled on March 25, 2019. In connection with the exchange, ETO issued approximately~~ ~~$4.21 billion~~ ~~aggregate principal amount of the following senior notes:~~Redemption

•~~$1.14~~On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of ~~7.50% senior notes~~ETO’s 2.900% Senior Notes due ~~2020;~~

•~~$995 million~~2025, $1.50 billion aggregate principal amount of ~~4.25% senior notes due 2023;~~the

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•~~$1.13~~Partnership’s 3.750% Senior Notes due 2030 and $2.00 billion aggregate principal amount of ~~5.875%~~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 ~~notes due 2024; and~~unsecured basis.

•~~$956~~Using proceeds from 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~~Senior Notes due ~~2027.~~

~~The senior notes were registered under the Securities Act~~February 15, 2020, ET’s $52 million aggregate principal amount of ~~1933 (as amended). The Partnership may redeem some or all~~7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually.5.36% Senior Notes due December 9, 2020.

HFOTCO Long-Term Debt

In connection with the contribution transactions discussed in Note 2, HFOTCO became a wholly-owned subsidiary of ETO in February 2020. As of June 30, 2020, HFOTCO had $225 million outstanding of tax exempt notes due 2050 (the “Ike Bonds”). The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially beIke Bonds are fully and unconditionally guaranteed by ~~our subsidiary, Sunoco Logistics Partners Operations L.P.,~~the Partnership, on a senior unsecured ~~basis so long as it guarantees any~~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 ~~our other long-term debt. The guarantee for each series of notes ranks equally~~which are substantially similar to those found in ~~right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.~~

~~ETO Senior Notes Offering and Redemption~~

~~In January 2019, ETO issued the following senior notes:~~

•~~$750 million aggregate principal amount of 4.50% senior notes due 2024;~~

•~~$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and~~

•~~$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.~~

The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually.

~~The senior notes rank equally in right of payment with~~ ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.

The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following:

•~~ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019;~~

•~~ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and~~

•~~Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.~~

~~Panhandle Senior Notes Redemption~~

~~In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.~~

~~Bakken Senior Notes Offering~~

~~In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline:~~

•~~$650 million aggregate principal amount of 3.625% senior notes due 2022;~~

•~~$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and~~

•~~$850 million aggregate principal amount of 4.625% senior notes due 2029.~~

~~The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken~~revolving credit facility, ~~and the facility was terminated.~~as further discussed below.

~~Sunoco LP Senior Notes Offering~~

In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing

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~~borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms.~~

~~USAC Senior Notes Offering~~

In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior unsecured notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.

Credit Facilities and Commercial Paper

ETO Term Loan

~~On October 17, 2019, ETO entered into a~~ETO’s term loan credit agreement ~~providing~~provides for a $2 billion three-year term loan credit ~~facility.~~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 ~~term loan agreement will be~~ETO Term Loan is unsecured and ~~will be~~is guaranteed by ~~our~~ETO’s subsidiary, Sunoco Logistics ~~Partners Operations L.P.~~ Operations.

~~Borrowings under~~As of June 30, 2020, the ~~term loan agreement will bear~~ETO Term Loan had $2 billion outstanding and was fully drawn. The weighted average interest ~~at a eurodollar~~ rate ~~or a base rate, at ETO’s option, plus an applicable margin. The applicable margin and applicable rate used in connection with the interest rates are based~~ on the ~~credit ratings assigned to the senior, unsecured, non-credit enhanced long-term debt~~total amount outstanding as of ~~ETO.~~ June 30, 2020 was 1.18%.

ETO Five-Year Credit Facility

ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. 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~~June 30, ~~2019,~~2020, the ETO Five-Year Credit Facility had ~~$2.61~~$3.01 billion of outstanding borrowings, ~~$2.15~~$1.11 billion of which was commercial paper. The amount available for future borrowings was ~~$2.32~~$1.90 billion, after taking into account letters of credit of ~~$77~~$86 million. The weighted average interest rate on the total amount outstanding as of ~~September~~June 30, ~~2019~~2020 was ~~2.77%~~1.34%.

ETO 364-Day Facility

ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November ~~29, 2019.~~27, 2020. As of ~~September~~June 30, ~~2019,~~2020, the ETO 364-Day Facility had 0 outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”), which matures in July 2023. As of ~~September~~June 30, ~~2019,~~2020, the Sunoco LP Credit Facility had ~~$154~~$158 million of outstanding borrowings and $8 million in standby letters of credit. As of ~~September~~June 30, ~~2019,~~2020, Sunoco LP had ~~$1.34~~$1.33 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of ~~September~~June 30, ~~2019~~2020 was ~~4.04%~~2.19%.

USAC Credit Facility

USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), with a further potential increase of $400 million, which matures in April 2023. As of ~~September~~June 30, ~~2019,~~2020, the USAC Credit Facility had ~~$395~~$448 million of outstanding borrowings and 0 outstanding letters of credit. As of ~~September~~June 30, ~~2019,~~2020, USAC had ~~$1.21~~$1.15 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of ~~$410~~$151 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of ~~September~~June 30, ~~2019~~2020 was ~~4.73%~~2.77%.

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SemCAMS Credit Facilities

SemCAMS is party to a credit agreement providing for a C$350 million (US$257 million at theJune 30, 2020exchange rate) senior secured term loan facility, a C$525 million (US$385 million at the June 30, 2020exchange rate) senior secured revolving credit facility, and a C$300 million (US$220 million at theJune 30, 2020exchange 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$183 million at the June 30, 2020exchange 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 June 30, 2020, the SemCAMS senior secured term loan facility and senior secured revolving credit facility had $251 million and $92 million, respectively, of outstanding borrowings. As of June 30, 2020, the KAPS Facility had0outstanding borrowings.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our ~~credit~~debt agreements as of ~~September~~June 30, ~~2019.~~2020.


7.	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~~June 30, ~~2019~~2020 included ~~(i)~~a balance of $477 million related

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to the USAC Preferred Units described below and ~~(ii) $22~~a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. In addition, redeemable noncontrolling interests includes a balance of $258 million in SemCAMS preferred shares.

USAC Preferred Units

~~In 2018,~~As of June 30, 2020, USAC ~~issued~~had 500,000 USAC Preferred Units ~~in a private placement at a price~~issued and outstanding. The holders of ~~$1,000 per USAC Preferred Unit, for total gross proceeds of $500 million.~~

~~The USAC Preferred Units~~these 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 convertible into USAC common units at the election of the holders beginning in 2021. 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 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 may elect to pay up to 50% of such redemption amount in USAC common units.

SemCAMS Redeemable Preferred Stock

As of June 30, 2020, SemCAMS had 329,830 shares of cumulative preferred stock issued and outstanding. The preferred stock is redeemable at SemCAMS’s option subsequent to January 3, 2021 at a redemption price of C$1,100 (US$807 at the June 30, 2020 exchange rate) per share. The preferred stock is redeemable by the holder contingent upon a change of control or liquidation of SemCAMS. The preferred stock is convertible to SemCAMS common shares in the event of an initial public offering by SemCAMS. Dividends on the preferred stock may be paid in-kind through June 30, 2021.


8.	EQUITY

~~Subsequent to the Energy Transfer Merger in October 2018, all~~All of our common units are owned by ET.

~~Class M Units~~

On July 1, 2019, ETO issued a total of 220.5 million units of a new class of limited partner interests titled Class M Units to ETP Holdco, a wholly-owned subsidiary of the Partnership, in exchange for the contribution of ETP Holdco’s equity ownership interest in PEPL to the Partnership.

The Class M Units generally do not have any voting rights. The Class M Units are entitled to quarterly cash distributions of $0.20 per Class M Unit. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class M Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements.

Preferred Units

As of ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018,~~2019, our outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units, 18,000,000 Series C Preferred Units, ~~and~~ 17,800,000 Series D Preferred Units and 32,000,000 Series E Preferred Units. As of ~~September~~June 30, ~~2019,~~2020, our outstanding preferred units also included ~~32,000,000~~500,000 Series F Preferred Units and 1,100,000 Series G Preferred Units.

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The following table summarizes changes in the amounts of our Series A, Series B, Series C, Series D, Series E, ~~Preferred Units.~~Series F and Series G preferred units for the six months ended June 30, 2020:



	Preferred Unitholders
	Series A			Series B			Series C			Series D			Series E			Series F			Series G			Total
Balance, December 31, 2019	$	958		$	556		$	440		$	434		$	786		$	—		$	—		$	3,174
Distributions to partners	(30		)	(18		)	(8		)	(9		)	(15		)	—			—			(80		)
Units issued for cash	—			—			—			—			—			494			1,086			1,580
Other, net	—			—			—			—			—			(1		)	(2		)	(3		)
Net income	15			9			8			9			15			6			15			77
Balance, March 31, 2020	943			547			440			434			786			499			1,099			4,748
Distributions to partners	—			—			(8		)	(8		)	(15		)	(11		)	(25		)	(67		)
Other, net	—			—			—			—			—			(1		)	—			(1		)
Net income	15			9			8			8			15			9			20			84
Balance, June 30, 2020	$	958		$	556		$	440		$	434		$	786		$	496		$	1,094		$	4,764

The following table summarizes changes in the amounts of our Series A, Series B, Series C, Series D and Series E preferred units for the ~~nine~~six months ended ~~September~~June 30, 2019:

Preferred Unitholders
Series A Series B Series C Series D Series E Total
Balance, December 31, 2018 $ 958
$ 556
$ 440
$ 434
$ —
$ 2,388
Distributions to partners (30 ) (18 ) (8 ) (8 ) —
(64 )
Net income 15
9
8
8
—
40
Balance, March 31, 2019 943
547
440
434
—
2,364
Distributions to partners —
—
(9 ) (9 ) —
(18 )
Units issued for cash —
—
—
—
780
780
Other, net —
—
—
—
(1 ) (1 )
Net income 15
9
9
9
11
53
Balance, June 30, 2019 958
556
440
434
790
3,178
Distributions to partners (29 ) (18 ) (8 ) (8 ) (19 ) (82 )
Net income 15
9
8
8
15
55
Balance, September 30, 2019 $ 944
$ 547
$ 440
$ 434
$ 786
$ 3,151

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~~The following table summarizes changes in the amounts of our Series A, Series B, Series C and Series D preferred units for the nine months ended September 30, 2018:~~


	Preferred Unitholders															Preferred Unitholders
	Series A			Series B			Series C			Series D			Total			Series A			Series B			Series C			Series D			Series E			Total
Balance, December 31, 2017	$	944		$	547		$	—		$	—		$	1,491
Balance, December 31, 2018																$	958		$	556		$	440		$	434		$	—		$	2,388
Distributions to partners	(15		)	(9		)	—			—			(24		)	(30		)	(18		)	(8		)	(8		)	—			(64		)
Other, net	(1		)	(1		)	—			—			(2		)
Net income	15			9			—			—			24			15			9			8			8			—			40
Balance, March 31, 2018	943			546			—			—			1,489
Units issued for cash	—			—			436			—			436
Other, net	—			1			—			—			1
Net income	15			9			6			—			30
Balance, June 30, 2018	958			556			442			—			1,956
Balance, March 31, 2019																943			547			440			434			—			2,364
Distributions to partners	(29		)	(18		)	(10		)	—			(57		)	—			—			(9		)	(9		)	—			(18		)
Units issued for cash	—			—			—			431			431			—			—			—			—			780			780
Other, net	—			—			(1		)	(1		)	(2		)	—			—			—			—			(1		)	(1		)
Net income	15			9			8			6			38			15			9			9			9			11			53
Balance, September 30, 2018	$	944		$	547		$	439		$	436		$	2,366
Balance, June 30, 2019																$	958		$	556		$	440		$	434		$	790		$	3,178

Series EF Preferred Units ~~Issuance~~

~~In April 2019, ETO~~On January 22, 2020, the Partnership issued ~~32 million~~500,000 of its ~~7.600%~~ Series EF Preferred Units representing limited partner interest in the Partnership, at a price ~~of $25 per unit, including 4 million Series E Preferred Units pursuant~~ to the ~~underwriters’ exercise~~public of their option to purchase additional preferred units. The total gross proceeds from the Series E Preferred Unit issuance were $800 million, including $100 million from the underwriters’ exercise of their option. The net proceeds were used to repay amounts outstanding under ETO’s Five-Year Credit Facility and for general partnership purposes.

$1,000 per unit. Distributions on the Series EF Preferred Units ~~will accrue and be~~are cumulative from and including the ~~date of~~ original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, ~~2024,~~2025, at a rate ~~of 7.600%~~equal to 6.750% per annum of the ~~stated~~$1,000 liquidation ~~preference of $25.~~preference. On and after May 15, ~~2024, distributions~~2025, the distribution rate on the Series EF Preferred Units will ~~accumulate at~~equal a percentage of the ~~$25~~$1,000 liquidation preference equal to ~~an annual floating~~the five-year U.S. treasury rate ~~of the three-month LIBOR, determined quarterly,~~ plus a spread of ~~5.161%~~5.134% per annum. The Series EF Preferred Units are redeemable at ETO’s option on or after May 15, ~~2024~~2025 at a redemption price of ~~$25~~$1,000 per Series E 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

On January 22, 2020, the Partnership issued 1,100,000 of its Series G Preferred Units representing limited partner interest in the Partnership, at a price to the public of $1,000 per unit. Distributions on the Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the 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. The Series G Preferred Units are redeemable at ETO’s option on or after May 15, 2030 at a redemption price of $1,000 per Series G

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Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Subsidiary Equity Transactions

Sunoco LP Equity Distribution Program

For the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, Sunoco LP issued 0 additional units under its at-the-market equity distribution program. As of ~~September~~June 30, ~~2019,~~2020, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

USAC Class B Conversion

On July 30, 2019, the 6,397,965 USAC Class B units held by the Partnership converted into 6,397,965 common units representing limited partner interests in USAC. These common units will participate in any future distributions declared by USAC.

USAC Distribution Reinvestment Program

During the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, distributions of ~~$0.7~~$0.9 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately ~~44,605~~96,592 USAC common units.

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Cash Distributions

Distributions on ETO’s preferred units declared and/or paid by the Partnership subsequent to December 31, ~~2018~~2019 were as follows:

Period Ended Record Date Payment Date
Series A⁽¹⁾

Series B⁽¹⁾
Series C Series D
Series E ⁽²⁾
December 31, 2018 February 1, 2019 February 15, 2019 $ 31.25
$ 33.125
$ 0.4609
$ 0.4766
$ —
March 31, 2019 May 1, 2019 May 15, 2019 —
—
0.4609
0.4766
—
June 30, 2019 August 1, 2019 August 15, 2019 31.25
33.125
0.4609
0.4766
0.5806
September 30, 2019 November 1, 2019 November 15, 2019 —
—
0.4609
0.4766
0.4750



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	—		—

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


⁽²⁾~~Series E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution.~~⁽²⁾	Series F Preferred Unit and Series 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.

Sunoco LP Cash Distributions

Distributions declared and/or paid by Sunoco LP to its common unitholders subsequent to December 31, ~~2018~~2019 were as follows:

Quarter Ended Record Date Payment Date Rate
December 31, 2018 February 6, 2019 February 14, 2019 $ 0.8255
March 31, 2019 May 7, 2019 May 15, 2019 0.8255
June 30, 2019 August 6, 2019 August 14, 2019 0.8255
September 30, 2019 November 5, 2019 November 19, 2019 0.8255



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2019	February 7, 2020	February 19, 2020	$	0.8255
March 31, 2020	May 7, 2020	May 19, 2020	0.8255
June 30, 2020	August 7, 2020	August 19, 2020	0.8255

USAC Cash Distributions

Distributions declared and/or paid by USAC to its common unitholders subsequent to December 31, ~~2018~~2019 were as follows:

Quarter Ended Record Date Payment Date Rate
December 31, 2018 January 28, 2019 February 8, 2019 $ 0.5250
March 31, 2019 April 29, 2019 May 10, 2019 0.5250
June 30, 2019 July 29, 2019 August 9, 2019 0.5250
September 30, 2019 October 28, 2019 November 8, 2019 0.5250



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2019	January 27, 2020	February 7, 2020	$	0.5250
March 31, 2020	April 27, 2020	May 8, 2020	0.5250
June 30, 2020	July 31, 2020	August 10, 2020	0.5250

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Accumulated Other Comprehensive Income (Loss)

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


	September 30, 2019			December 31, 2018			June 30, 2020			December 31, 2019
Available-for-sale securities	$	10		$	2		$	13		$	13
Foreign currency translation adjustment	(5		)	(5		)	(32		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(41		)	(48		)	(14		)	(25		)
Investments in unconsolidated affiliates, net	(4		)	9			(17		)	(1		)
Subtotal							(50		)	(18		)
Amounts attributable to noncontrolling interest							29			—
Total AOCI, net of tax	$	(40	)	$	(42	)	$	(21	)	$	(18	)


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.

ETC Sunoco historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with ETC Sunoco’s 2004 through 2011 years, ETC Sunoco filed amended returns with the Internal Revenue Service (“IRS”) excluding these government incentive payments from federal taxable income. The IRS denied the

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amended returns and ETC Sunoco petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the CFC ruled against ETC Sunoco, and the Federal Circuit affirmed the CFC’s ruling on November 1, 2018. ETC Sunoco filed a petition for rehearing with the Federal Circuit on December 17, 2018, and this was denied on January 24, 2019. ETC Sunoco filed a petition for writ of certiorari with the United States Supreme Court that was docketed on May 24, 2019, to review the Federal Circuit’s affirmation of the CFC’s ruling. The government filed its response to ETC Sunoco’s petition on July 24, 2019. In October 2019, the Supreme Court denied the petition related to the years 2004 through 2009. The years 2010 through 2011 are on extension with the IRS. Due to the uncertainty surrounding the litigation, a reserve of ~~$530 million~~ was previously established for the full amount of the pending refund claims, and the receivable and reserve for this issue were netted in the balance sheet. Subsequent to the Supreme Court’s denial of the petition in October 2019, the receivable and reserve have been reversed, with no impact to the Partnership’s financial position or results of operations.


10.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

FERC Proceedings

By ~~order~~Order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the ~~order~~Order dated October 1, 2019. A hearing in the combined proceedings is scheduled for August 2020, with an initial decision expected in early 2021.

By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest Gas filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 29, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue.

In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. On July 22, 2019, Sea Robin filed an Offer of Settlement in this Section 4 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 17, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue.

Commitments

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

Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

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,
2019 2018 2019 2018
ROW expense $ 5
$ 5
$ 17
$ 18



	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
ROW expense	$	10	$	6	$	19	$	12

PES Refinery Fire and Bankruptcy

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

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On July 21, 2019, ~~(the "Petition Date"),~~ PES Holdings, LLC and seven of its subsidiaries (collectively, the ~~"Debtors"~~“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

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States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have ~~announced an intent to temporarily cease refinery operations. The Debtors have~~ also defaulted on a $75 million note payable to a subsidiary of the Partnership. ~~The~~In June 2020, the Partnership ~~has not~~received $12 million from PES on the note payable and recorded a ~~valuation allowance related to~~reserve for the remaining $63 million note ~~receivable as of September 30, 2019, because management is not yet able to determine the collectability of the note in bankruptcy.~~balance.

In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of ~~September~~June 30, ~~2019,~~2020, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such ~~claims,~~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;~~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, as the Debtors have expressed an intent to rebuild the refinery with the proceeds of insurance claims while concurrently running a sale process for its assets and operations.~~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.

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.

Dakota Access Pipeline

On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access, LLC (“Dakota Access”) to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“challenging permits issued by the ~~Court”~~United States Army Corps of Engineers (“USACE”) ~~against~~permitting 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 ~~and challenged~~allowing the ~~legality of these permits and claimed violations of the National Historic Preservation Act (“NHPA”). SRST also sought a preliminary injunction~~pipeline to ~~rescind~~cross land owned by the USACE ~~permits while~~adjacent to the ~~case was pending, which the Court denied on September 9, 2016.~~Missouri River. Dakota Access ~~intervened in~~and the ~~case. The~~ Cheyenne River Sioux Tribe (“CRST”) ~~also~~ intervened. ~~SRST~~Separate lawsuits filed ~~an amended complaint and added claims based on treaties between SRST and CRST and the United States and statutes governing the use of government property.~~

In February 2017, in response to a Presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which motion was denied, and raised claims based on the religious rights of CRST.

~~In June 2017, SRST and CRST amended their complaints to incorporate religious freedom and other claims. In addition,~~by the Oglala Sioux and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.

On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court concluded that the USACE had not violated trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy ActTribe (“~~NEPA”~~OST”) and ~~other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes.~~

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~~In November 2017,~~ the Yankton Sioux Tribe (“YST”)~~, moved~~ were consolidated with this action and several individual tribal members intervened (collectively with SRST and CRST, the “Tribes”). Plaintiffs and Defendants filed cross motions for ~~partial~~ summary ~~judgment asserting claims similar to those already litigated and decided by~~judgment. On March 25, 2020, the Court ~~in its June~~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 have filed notices of appeal with the United States Court of Appeals for the District of Columbia (“Court of Appeals”) with respect to the Court’s ruling related to the preparation of an Environmental Impact Statement and also filed motions for a stay of the Court’s July 6, 2020 Order. On July 14, ~~2017 decision on similar motions by CRST~~2020, the Court of Appeals administratively stayed the Court’s July 6 Order and ~~SRST. YST argues~~ordered further briefing with respect to the motion to stay. 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 stay of the March 25 Order and the remaining portion of the July 6 Order vacating the easement. As a result, no court order stops Dakota Access from continuing to operate the Pipeline. The August 5 Order contemplates that the USACE will make a determination under its regulations and ~~Fish~~procedures whether vacating the easement requires oil to stop flowing. The Order also contemplates further proceedings in the District Court, and ~~Wildlife Service violated NEPA,~~it expedites the ~~Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline.~~

On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third party to review its complianceappeal with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the Court on December 29, 2017 and February 28, 2018, respectfully.

On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions sought an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access and the USACE opposed both motions. On April 16, 2018, the Court denied both motions.

On March 19, 2018, the Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST.

On May 3, 2018, the Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they would conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they would need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. On October 1, 2018, the USACE produced a detailed remand analysis document supporting that determination. The Tribes and certain of the individuals sought leave of the Court to amend their complaints to challenge the remand process and the USACE’s decision on remand.

On January 3, 2019, the Court granted the Tribes’ requests to supplement their respective complaints challenging the remand process, subject to defendants’ right to argue later that such supplementation may be overbroad and not permitted by law. On January 10, 2019, the Court denied the Oglala Sioux Tribe’s motion to amend its complaint to expand one of its pre-remand claims.

On January 17, 2019, the DOJ, on behalf of the USACE, moved to stay the litigation in light of the lapse in appropriations for the DOJ. The Tribes and individual plaintiffs opposed that request. On January 28, 2019, the USACE moved to withdraw this motion because appropriations for the DOJ had been restored. The Court granted this motion the next day.

On January 31, 2019, the USACE notified the Court that it had provided the administrative record for the remand to all parties. On February 27, 2019, the four Tribes filed a joint motion challenging the completeness of the record. The USACE opposed this motion in part, and Dakota Access opposed in full.

On May 8, 2019, the Court issued an order on Plaintiffs’ motion to complete the administrative record, requiring the parties to submit additional information so that the Court can determine what documents, if any, should be added to the record. Following submittal of additional information by the parties, the Court issued an order on June 11, 2019 that determined which documents were to be added to the record. Plaintiffs filed motions for summary judgment on August 16, 2019, and Defendants filed their opposition and cross motions on October 9, 2019. Briefing is scheduledbriefing to conclude by ~~November 20, 2019.~~September 30, 2020.

~~While we believe that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome.~~ Energy Transfer cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access ~~project.~~

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project, but expects after the law and complete record are fully considered, the issues in this litigation will be resolved in a manner that will allow the pipeline to continue to operate.

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”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage ~~wells.~~ wells, however,

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Lone Star is still quantifying the extent of its incurred and ongoing damages and has obtained, and will continue to seek, reimbursement for these losses.

MTBE Litigation

ETC Sunoco Holdings LLC and Sunoco (R&M), LLC (collectively, “Sunoco”) 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.

As of ~~September~~June 30, ~~2019~~,2020, Sunoco is a defendant 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

Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETO merger (the “Regency Merger”). All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint 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 GP, and the members of Regency’s board of directors.

The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership ~~agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith or fair to Regency.~~agreement. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. ~~Dieckman appealed. On January 20, 2017,~~Plaintiff appealed, and the Delaware Supreme Court reversed the judgment of the Court of Chancery. ~~On May 5, 2017,~~ Plaintiff then filed an Amended Verified Class Action ~~Complaint.~~Complaint, which defendants moved to dismiss. The ~~defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the~~ Court of Chancery ~~issued an Order granting~~granted in part and ~~denying~~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”). ~~On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. On April 26, 2019, the~~The Court of Chancery later granted ~~Dieckman’s~~Plaintiff’s unopposed motion for class certification. ~~On May 14,~~Trial was held on December 10-16, 2019, ~~the Regency Defendants filed~~and a ~~motion for summary judgment arguing that Dieckman’s claims fail because the Regency Defendants relied on the advice of their financial advisor in approving the Regency Merger. Also~~post-trial hearing was held on May 14, 2019, Dieckman filed a motion for partial summary judgment arguing, among other things, that Regency’s conflicts committee was not properly formed. On October 29, 2019, the court granted Plaintiff’s summary judgment motion, holding that Regency failed (1) to form a valid conflicts committee such that Regency failed to satisfy the Special Approval safe harbor in connection with the merger, and (2) to issue a proxy that was not materially misleading such that Regency failed to satisfy the Unitholder Approval safe harbor in connection with the merger. The court denied Defendants’ summary judgment motion which argued that Defendants approved the merger in good faith because they relied upon the fairness opinion of an investment bank. The court held that fact questions existed regarding whether Defendants actually relied upon the fairness opinion given by JP Morgan when voting in favor of the merger. Trial is currently set for December 10-16, 2019.6, 2020.

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 and intend to vigorously defend against ~~it and any others that may be filed in connection with the Regency Merger.~~it.

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~~Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation~~

On January 27, 2014, a trial commenced between ETO against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETO. The jury also found that ETO owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETO and awarded ETO $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETO shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETO’s motion for rehearing to the Court of Appeals was denied. On November 27, 2017, ETO filed a Petition for Review with the Texas Supreme Court. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. On June 28, 2019, the Texas Supreme Court granted ETO’s petition for review and oral argument was heard on October 8, 2019. The parties now await a decision.

Rover

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and ~~Pretec Directional Drilling, LLC (“Pretec”)~~other defendants seeking to recover ~~approximately $2.6 million in~~ civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added asThe defendants ~~on April 17, 2018 and July 18, 2018.~~

Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss, and Ohio EPA filed a motion in opposition. The State’s opposition to those motions was filed on October 12, 2018. Rover and other Defendants filed their replies on November 2, 2018. On March 13, 2019, the courtwhich were granted ~~Rover and the other Defendants’ motion to dismiss~~ on all counts. ~~On April 10, 2019, the~~The Ohio EPA ~~filed a notice of appeal. The Ohio EPA’s appeal is now pending before~~appealed, and on December 9, 2019, the Fifth District ~~court~~Court of ~~appeals. Briefing was completed in August of 2019 and oral argument has been set for November 5, 2019.~~

~~In January 2018,~~Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24, 2018 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed bysought review from the Ohio ~~EPA. In addition, although~~Supreme Court, which the ~~HDD operations were crossing~~defendants opposed in briefs filed in February 2020. On April 22, 2020, the ~~same resource as that which led to an inadvertent release~~Ohio Supreme Court granted the Ohio EPA’s request for review. Briefing is underway and will conclude at the end of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs. Construction of Rover is now complete and the pipeline is fully operational.August 2020.

Bayou Bridge

On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. ~~They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process.~~ ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. ~~On March 27, 2018, Bayou Bridge filed an answer to the complaint.~~

On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal and a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order.

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On March ~~2, 2018, Bayou Bridge filed a motion to stay~~25, 2020, the ~~preliminary injunction~~Court granted summary judgment in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the meritsfavor of the USACE. Plaintiffs did not appeal ~~that is, whether~~by the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the district court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunctiondeadline, and ~~remanded~~ the case ~~back to the district court. Construction is ongoing.~~

On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 18, 2018. On September 18, 2018, Plaintiffs filed a motion for partial summary judgment on the issue of the USACE’s analysis of the risks of an oil spill once the pipeline is in operation. On November 6, 2018, the court struck plaintiffs’ motion as premature.

~~At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiffs’ original complaint, which it~~ has done. Challenges to the completeness of the record have been briefed and are currently pending before the court. At the October 18, 2018 conference, the court also scheduled summary judgment briefing on Plaintiffs’ original complaint; briefing is scheduled to conclude by the end of 2019.

On December 28, 2018, Judge Dick issued a General Order for the Middle District of Louisiana holding in abeyance all civil matters where the United States is a party. Notwithstanding the General Order, on January 11, 2019, Plaintiffs prematurely filed a Motion for Summary Judgment on its National Environmental Policy Act and Clean Waters Act claims.

On January 23, 2019, Plaintiffs filed a Second Motion for Preliminary Injunction based on alleged permit violations, which the court later denied. On February 11, 2019, the court denied Plaintiffs’ August 14, 2018 motion for leave to amend their complaint.

On February 14, 2019, Judge Dick ordered that all summary judgment briefing is stayed until the court rules on the motions challenging the completeness of the administrative record. Judge Dick further ordered that once those motions are decided, the parties will be allowed to update any summary judgment briefs they have already filed, if necessary, and that the court will set new briefing deadlines.

~~On April 26, 2019, Plaintiffs filed a motion seeking reconsideration of Judge Dick’s February 14, 2019 order staying summary judgment briefing. Defendants filed their oppositions on May 6, 2019.~~

~~On May 14, 2019, Judge Dick issued orders denying the outstanding record motions and Plaintiffs’ motion seeking reconsideration of the February 14, 2019 order.~~

On May 22, 2019, in a telephonic status conference, Judge Dick set a schedule for summary judgment briefing. Plaintiffs filed their motion for summary judgment on July 8, 2019 and Defendants filed their oppositions and cross-motions on August 9, 2019. Briefing is now concluded and the motions are before the court.concluded.

Revolution

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line ~~in the vicinity of Ivy Lane~~ located in Center Township, Beaver County, Pennsylvania. There were no ~~injuries, but there were evacuations of local residents as a precautionary measure. The~~injuries. On February 8, 2019, the Pennsylvania Department of Environmental Protection (“PADEP”) and the Pennsylvania Public Utility Commission (“PUC”) are investigating the incident. On October 29, 2018, PADEP issued a Compliance Order requiring our subsidiary, ETC Northeast Pipeline, LLC (“ETC Northeast”), to cease all earth disturbance activities at the site (except as necessary to repair and maintain existing Best Management Practices (“BMPs”) and temporarily stabilize disturbed areas), implement and/or maintain the Erosion and Sediment BMPs at the site, stake the limit of disturbance, identify and report all areas of non-compliance, and submit an updated Erosion and Sediment Control Plan, a Temporary Stabilization Plan, and an updated Post Construction Stormwater Management Plan. The scope of the Compliance Order has been expanded to include the disclosure to PADEP of alleged violations of environmental permits with respect to various construction and post-construction activities and restoration obligations along the 42-mile route of the Revolution line. ETC Northeast filed an appeal of the Compliance Order with the Pennsylvania Environmental Hearing Board.

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Petition. ETC Northeast and PADEP have since agreed to a Stipulated Order regarding the issues raised in the Compliance Order, which obviated the need for a hearing. The Commonwealth Court approved the Stipulated Order on March 26, 2019. On February 8, 2019, PADEP also issued a Permit Hold on any requests for approvals/permits or permit amendments ~~made by us or any of our subsidiaries~~ for any ~~projects~~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 March 11, 2019.~~Board. On May 14, 2019, PADEP issued a Compliance Order related to impacts to streams and wetlands. The Partnership filed an appeal of the Streams and Wetlands Compliance Order on June 14, 2019. On August 5, 2019, ETC Northeast andJanuary 3, 2020, the Partnership ~~received~~entered into a ~~Subpoena to Compel Documents~~Consent Order and ~~Information related to~~Agreement with the ~~Revolution pipeline and~~PADEP in which, among other things, the ~~Incident. ETC Northeast and~~Permit Hold was lifted, the Partnership ~~filed an appeal of the Subpoena on September 4, 2019.~~

~~The Partnership continues~~agreed to ~~work through these issues with PADEP during the pendency of these appeals.~~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 (“DA”) sent a letter to the Partnership stating that ithis 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~~Grand Jury in Chester County, ~~Pennsylvania. As part of the Grand Jury proceedings, since April and August 2019, the Partnership was served with a total of forty-one grand jury~~Pennsylvania, which has issued subpoenas seeking ~~a variety of~~ documents and ~~records sought by the Chester County Investigation Grand Jury.~~testimony. On September 24, 2019, the ~~Chester County District Attorney~~former 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 ~~intends to respond~~responded to the ~~notice~~Notice of Intent within the proscribed time period. To date, the Partnership is not aware of any further action with regard to this Notice.

In December 2019, the former 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.

Delaware County, Pennsylvania Investigation

On March 11, 2019, the Delaware County District Attorney’s Office (“~~Delaware County D.A.”~~DA”) announced that the ~~Delaware County D.A.~~DA and the Pennsylvania Attorney General’s Office, at the request of the ~~Delaware County D.A.,~~DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. ~~The Partnership has not been appraised of~~On March 16, 2020, the ~~specific conduct under investigation. This investigation is ongoing.~~Pennsylvania Attorney General Office 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 will cooperate with the ~~investigation,~~subpoena, it intends to vigorously defend ~~itself against these allegations.~~itself.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018,~~2019, accruals of approximately ~~$61~~$92 million and ~~$53~~$98 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.

~~On April 25, 2018, and~~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 ~~amended on April~~of June 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against SPLP before the PUC. Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2”2020 or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’sDecember 31, 2019.

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Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in the Township.

Following a hearing on May 7 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the PADEP has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018, the PUC entered an Order lifting the stay of construction on ME2 and ME2x in the Township with respect to four of the eight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of permit modifications for two of the four remaining construction sites, the PUC lifted the construction stay on those two sites as well. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue this matter. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition.

Briefing in the Commonwealth Court has been completed. On June 3, 2019, the Commonwealth Court heard argument on whether Senator Dinniman has standing. On September 9, 2019, the Commonwealth Court issued an Opinion finding that Senator Dinniman did not have standing in either his personal or representational capacity. The Commonwealth Court’s Order remanded the case to the PUC to dissolve the interim emergency injunction and dismiss the Complaint. Senator Dinniman has not sought to appeal the ruling.

Previously, on March 29, 2019, SPLP filed a supplemental affidavit with the PUC in accordance with the established procedure to request the PUC lift the stay of construction of ME2 for one of the remaining work locations in the Township - Shoen Road. That same day, Senator Dinniman filed a letter objecting to SPLP’s request, arguing the Commonwealth Court’s order staying all proceedings barred the PUC from issuing an approval to lift the stay of construction of ME2 at Shoen Road. Given the Commonwealth Court’s September 9 opinion, the PUC dissolved the injunction on September 19, 2019 and work on Shoen Road commenced.

~~NaN amounts have been recorded in our~~ ~~September 30, 2019~~ ~~or December 31, 2018 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.~~

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, 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.

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Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on ~~the~~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 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.~~

On January 3, 2018, PADEP issued an Administrative Order to SPLP directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Ordertrustees related to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that SPLP had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018.Caddo Parish, Louisiana release.

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~~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 ~~rupture~~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.

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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 ~~potentially~~ be ~~held~~contractually responsible for contamination caused by other parties.

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


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

•

~~ETC~~ Sunoco 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~~June 30, ~~2019, ETC~~2020, Sunoco had been named as a PRP at approximately 3830 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. ~~ETC~~ Sunoco is usually one of a number of companies identified as a PRP at a site. ~~ETC~~ Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon ~~ETC~~ Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that ~~would~~ require disclosure in our consolidated financial statements.


	September 30, 2019		December 31, 2018		June 30, 2020		December 31, 2019
Current	$	46	$	42	$	43	$	46
Non-current	276		295		261		274
Total environmental liabilities	$	322	$	337	$	304	$	320

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~~June 30, ~~2019~~2020 and ~~2018,~~2019, the Partnership recorded ~~$16~~$7 million and ~~$17~~$9 million, respectively, of expenditures related to environmental cleanup programs. During the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018,~~2019, the Partnership recorded ~~$31~~$15 million and ~~$32~~$15 million, respectively, of expenditures related to environmental cleanup programs.

Our pipeline operations are subject to regulation by the United States Department of Transportation under ~~the~~ PHMSA, pursuant to which ~~the~~ PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, ~~the~~ PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

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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

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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 1514 depicts the disaggregation of revenue by segment.

Contract Balances with Customers

The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.

The Partnership recognizes a contract liability if the ~~customer's~~customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but ~~allows~~allow customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as ~~prepayments or~~ 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, 2019				$	377
Additions				413
Revenue recognized				(405		)
Balance, June 30, 2020				$	385
	Contract Liabilities
Balance, December 31, 2018	$	392		$	394
Additions	448			300
Revenue recognized	(491		)	(315		)
Balance, September 30, 2019	$	349

Balance, January 1, 2018	$	205
Additions	409
Revenue recognized	(211		)
Balance, September 30, 2018	$	403
Balance, June 30, 2019				$	379

The balances of receivables from contracts with customers listed in the table below ~~all of which are attributable to Sunoco LP,~~ include both current trade receivables and long-term receivables, net of allowance for ~~doubtful accounts.~~expected credit losses. The allowance for ~~receivables~~expected credit losses represents Sunoco ~~LP’s~~LP's best estimate of the probable losses associated with potential customer defaults. Sunoco LP ~~determines~~estimates the ~~allowance~~expected credit losses based on historical write-off experience by industry and ~~on a specific identification basis.~~current expectations of future credit losses.

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The balances of Sunoco LP’s contract assets as of ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018~~2019 were as follows:


	September 30, 2019		December 31, 2018		June 30, 2020		December 31, 2019
Contract asset balances:
Contract asset	$	102	$	75
Contract assets					$	128	$	117
Accounts receivable from contracts with customers	403		348		263		366

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Costs to Obtain or Fulfill a Contract

Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g., sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in the future, and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the three months ended ~~September~~June 30, 2020 and 2019 ~~and 2018~~ was $4$5 million and $4 million, respectively. The amount of amortization expense that Sunoco LP recognized for the ~~nine~~six months ended ~~September~~June 30, 2020 and 2019 ~~and 2018~~ was ~~$12~~$10 million and ~~$10~~$8 million, , respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.

~~Performance Obligations~~

At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total expected contract consideration 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, 2019, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $41.13 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:

Years Ending December 31,
2019 (remainder) 2020 2021 Thereafter Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2019 $ 1,716
$ 5,544
$ 4,812
$ 29,062
$ 41,134


12.	~~LEASE ACCOUNTING~~

~~Lessee Accounting~~

The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.

At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership, and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of

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~~ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.~~

To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.

Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.

~~For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.~~

~~The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of September 30, 2019 were as follows:~~

September 30, 2019
Operating leases:
Lease right-of-use assets, net $ 850
Operating lease current liabilities 57
Accrued and other current liabilities 1
Non-current operating lease liabilities 807
Finance leases:
Property, plant and equipment, net $ 2
Lease right-of-use assets, net 39
Accrued and other current liabilities 1
Current maturities of long-term debt 7
Long-term debt, less current maturities 35
Other non-current liabilities 2

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~~The components of lease expense for the three and nine months ended September 30, 2019 were as follows:~~

Income Statement Location Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019
Operating lease costs:
Operating lease cost Cost of goods sold $ 7
$ 23
Operating lease cost Operating expenses 18
54
Operating lease cost Selling, general and administrative 3
10
Total operating lease costs 28
87
Finance lease costs:
Amortization of lease assets Depreciation, depletion and amortization 2
4
Interest on lease liabilities Interest expense, net of capitalized interest 1
1
Total finance lease costs 3
5
Short-term lease cost Operating expenses 10
33
Variable lease cost Operating expenses 3
11
Lease costs, gross 44
136
Less: Sublease income Other revenue 14
37
Lease costs, net $ 30
$ 99

~~The weighted average remaining lease terms and weighted average discount rates as of September 30, 2019 were as follows:~~



	~~September 30, 2019~~
~~Weighted-average remaining lease term (years):~~
~~Operating leases~~	22
~~Finance leases~~	6
~~Weighted-average discount rate (%):~~
~~Operating leases~~	5	%
~~Finance leases~~	5	%

~~Cash flows and non-cash activity related to leases for the nine months ended September 30, 2019 were as follows:~~

Nine Months Ended September 30, 2019
Operating cash flows from operating leases $ (78 )
Lease assets obtained in exchange for new finance lease liabilities 37
Lease assets obtained in exchange for new operating lease liabilities 36

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~~Maturities of lease liabilities as of September 30, 2019 are as follows:~~

Operating Leases Finance Leases Total
2019 (remainder) $ 27
$ 2
$ 29
2020 96
10
106
2021 87
10
97
2022 75
10
85
2023 70
9
79
Thereafter 1,170
10
1,180
Total lease payments 1,525
51
1,576
Less: present value discount 660
6
666
Present value of lease liabilities $ 865
$ 45
$ 910

~~Lessor Accounting~~

Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.

~~Rental income included in other revenue in our consolidated statement of operations for the three and nine months ended September 30, 2019 was $39 million and $111 million, respectively.~~

~~Future minimum operating lease payments receivable as of September 30, 2019 are as follows:~~

Lease Receivables
2019 (remainder) $ 25
2020 85
2021 69
2022 56
2023 4
Thereafter 7
Total undiscounted cash flows $ 246


~~13.~~	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.

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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 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

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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, 2019			December 31, 2018			June 30, 2020			December 31, 2019
	Notional Volume		Maturity	Notional Volume		Maturity	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX ⁽¹⁾	20,563		2019-2024	16,845		2019-2020	(20,433	)	2020-2024	(35,208	)	2020-2024
Fixed Swaps/Futures	1,723		2019-2020	468		2019	373		2020-2021	1,483		2020
Options – Puts	—		—	10,000		2019
Power (Megawatt):
Forwards	2,847,350		2019-2029	3,141,520		2019	1,338,776		2020-2029	3,213,450		2020-2029
Futures	222,440		2019-2020	56,656		2019-2021	204,090		2020-2021	(353,527	)	2020
Options – Puts	515,317		2019-2020	18,400		2019	(340,743	)	2020	51,615		2020
Options – Calls	(756,153	)	2019-2021	284,800		2019	(1,268,532	)	2020-2021	(2,704,330	)	2020-2021
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(23,653	)	2019-2022	(30,228	)	2019-2021	(27,713	)	2020-2022	(18,923	)	2020-2022
Swing Swaps IFERC	22,365		2019-2020	54,158		2019-2020	(35,590	)	2020-2021	(9,265	)	2020
Fixed Swaps/Futures	2,323		2019-2021	(1,068	)	2019-2021	(10,708	)	2020-2022	(3,085	)	2020-2021
Forward Physical Contracts	(29,492	)	2019-2021	(123,254	)	2019-2020	(23,980	)	2020-2021	(13,364	)	2020-2021
NGLs (MBbls) – Forwards/Swaps	(9,687	)	2019-2021	(2,135	)	2019	(8,830	)	2020	(1,300	)	2020-2021
Refined Products (MBbls) – Futures	(906	)	2019-2021	(1,403	)	2019	(3,370	)	2020-2022	(2,473	)	2020-2021
Crude (MBbls) – Forwards/Swaps	9,510		2019-2020	20,888		2019	3,393		2020	4,465		2020
Corn (thousand bushels)	(1,760	)	2019	(1,920	)	2019	—		—	(1,210	)	2020
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(31,703	)	2019-2020	(17,445	)	2019	(43,235	)	2020-2021	(31,780	)	2020
Fixed Swaps/Futures	(31,703	)	2019-2020	(17,445	)	2019	(43,235	)	2020-2021	(31,780	)	2020
Hedged Item – Inventory	31,703		2019-2020	17,445		2019	43,235		2020-2021	31,780		2020


⁽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, 2019 December 31, 2018
July 2019⁽²⁾
Forward-starting to pay a fixed rate of 3.56% and receive a floating rate $ —
$ 400
July 2020⁽²⁾
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
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
—
March 2019 Pay a floating rate and receive a fixed rate of 1.42% —
300



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	June 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


⁽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 interest rate swaps were terminated in January 2020.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrial end-users, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

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

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

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Derivative Summary

The following table provides a summary of our derivative assets and liabilities:


	Fair Value of Derivative Instruments										Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives						Asset Derivatives				Liability Derivatives
	September 30, 2019		December 31, 2018		September 30, 2019			December 31, 2018			June 30, 2020		December 31, 2019		June 30, 2020			December 31, 2019
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	16	$	—	$	—		$	(13	)	$	18	$	24	$	(22	)	$	—
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	543		402		(520		)	(397		)	370		319		(367		)	(350		)
Commodity derivatives	120		158		(77		)	(173		)	67		41		(77		)	(39		)
Interest rate derivatives	—		—		(528		)	(163		)	—		—		(577		)	(399		)
	663		560		(1,125		)	(733		)	437		360		(1,021		)	(788		)
Total derivatives	$	679	$	560	$	(1,125	)	$	(746	)	$	455	$	384	$	(1,043	)	$	(788	)

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, 2019			December 31, 2018			September 30, 2019			December 31, 2018				Balance Sheet Location	June 30, 2020			December 31, 2019			June 30, 2020			December 31, 2019
Derivatives without offsetting agreements		Derivative liabilities	$	—		$	—		$	(528	)	$	(163	)		Derivative liabilities	$	—		$	—		$	(577	)	$	(399	)
Derivatives in offsetting agreements:	Derivatives in offsetting agreements:														Derivatives in offsetting agreements:
OTC contracts		Derivative assets (liabilities)	120			158			(77		)	(173		)		Derivative assets (liabilities)	67			41			(77		)	(39		)
Broker cleared derivative contracts		Other current assets (liabilities)	559			402			(520		)	(410		)		Other current assets (liabilities)	388			343			(389		)	(350		)
Total gross derivatives	Total gross derivatives		679			560			(1,125		)	(746		)	Total gross derivatives		455			384			(1,043		)	(788		)
Offsetting agreements:	Offsetting agreements:														Offsetting agreements:
Counterparty netting		Derivative assets (liabilities)	(64		)	(47		)	64			47				Derivative assets (liabilities)	(53		)	(18		)	53			18
Counterparty netting		Other current assets (liabilities)	(519		)	(397		)	519			397				Other current assets (liabilities)	(349		)	(318		)	349			318
Total net derivatives	Total net derivatives		$	96		$	116		$	(542	)	$	(302	)	Total net derivatives		$	53		$	48		$	(641	)	$	(452	)

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 depending on the anticipated settlement date.

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The following ~~tables summarize~~table summarizes the location and amounts recognized in ~~income~~our consolidated statements of operations with respect to our derivative financial instruments:

Location of Gain Recognized in Income on Derivatives Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 2019 2018
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives Cost of products sold $ —
$ —
$ —
$ 9


	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives											Location	Amount of Gain (Loss) on Derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,							Three Months Ended June 30,						Six Months Ended June 30,
		2019			2018		2019			2018				2020			2019			2020			2019
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3		$	3	$	15		$	36		Cost of products sold	$	(5	)	$	(20	)	$	11		$	(14	)
Commodity derivatives – Non-trading	Cost of products sold	21			21		(53		)	(345		)	Cost of products sold	(96		)	(29		)	97			(41		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(175		)	45		(371		)	117			Losses on interest rate derivatives	(3		)	(122		)	(332		)	(196		)
Total		$	(151	)	$	69	$	(409	)	$	(192	)		$	(104	)	$	(171	)	$	(224	)	$	(251	)


~~14.~~13.	RELATED PARTY TRANSACTIONS

~~In October 2018, in connection with the Energy Transfer Merger, ET and ETO entered into an intercompany promissory note due from ET to ETO (“~~ET-ETO Promissory Note A”) for an aggregate amount up to $2.20 billion that accrues interest at a weighted average rate based on interest payable by ETO on its outstanding indebtedness. The ET-ETO Promissory Note A matures on October 18, 2019.

As of ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018, the ET-ETO Promissory Note A had outstanding balances of $0 million and $440 million, respectively.~~

~~In March~~ 2019, ~~in connection with the ET-ETO senior notes exchange, ET and ETO entered into an intercompany~~ETO’s promissory note ~~due~~receivable from ET to ETO (“ET-ETO Promissory Note B” and, together with the ET-ETO Promissory Note A, the “ET-ETO Promissory Notes”) for an aggregate amount up to $4.25 billion that accrues interest at a weighted average rate based on interest payable by ETO on its outstanding indebtedness. The ET-ETO Promissory Note B matures on December 31, 2024. As of September 30, 2019, the ET-ETO Promissory Note B had an outstanding balance of ~~$3.69 billion.~~$3.0 billion and $3.7 billion, respectively, and ETO’s long-term intercompany payable to ET had an outstanding balance of $135 million and $104 million, respectively. The outstanding promissory note receivable and intercompany payable are reflected on a net basis in the Partnership’s consolidated balance sheets.

Interest income attributable to ~~the ET-ETO Promissory Notes~~promissory notes from ET included in other income, net in our consolidated statements of operations for the three ~~and nine~~ months ended ~~September~~June 30, 2020 and 2019 was ~~$56~~$38 million and ~~$144 million,~~$67 million. respectively.

~~As of September 30, 2019, ETO has a long-term intercompany payable due~~ Interest income attributable to ~~ET of $85 million, which has been netted against the outstanding~~ promissory notes ~~receivable~~from ET included in other income, net in our consolidated ~~balance sheet.~~statements of operations for the six months ended June 30, 2020 and 2019 was $82 million and $88 million, respectively.

The Partnership also 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.

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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,
2019 2018 2019 2018
Revenues from related companies $ 129
$ 103
$ 374
$ 325



	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Revenues from related companies	$	142	$	136	$	275	$	245

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


	September 30, 2019		December 31, 2018		June 30, 2020		December 31, 2019
Accounts receivable from related companies:
ET	$	71	$	65	$	—	$	8
FGT	51		25		13		50
Phillips 66	36		42		9		36
Traverse	25		—		62		42
Other	41		44		55		31
Total accounts receivable from related companies	$	224	$	176	$	139	$	167

Accounts payable to related companies:
ET	$	—	$	59	$	21	$	—
Other	23		60		15		31
Total accounts payable to related companies	$	23	$	119	$	36	$	31


~~15.~~14.	REPORTABLE SEGMENTS

~~As a result of the Energy Transfer Merger in October 2018, our reportable segments were reevaluated and~~Our financial statements currently reflect the following reportable segments, which conduct their business primarily in the United States:

•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.

~~The investment in USAC segment reflects the results of USAC beginning April 2018, the date that the Partnership obtained control of USAC.~~

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

~~Table of Contents~~

reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas ~~sales.~~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”). 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

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.

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The following tables present financial information by segment:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2020			2019			2020			2019
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	675		$	846		$	2,115		$	2,424		$	465		$	671		$	1,001		$	1,440
Intersegment revenues	89			76			270			186			51			94			108			181
	764			922			2,385			2,610			516			765			1,109			1,621
Interstate transportation and storage:
Revenues from external customers	475			440			1,454			1,174			440			487			899			979
Intersegment revenues	4			5			16			13			5			6			10			12
	479			445			1,470			1,187			445			493			909			991
Midstream:
Revenues from external customers	704			537			1,704			1,571			391			337			892			1,000
Intersegment revenues	876			1,716			2,792			4,170			627			861			1,296			1,916
	1,580			2,253			4,496			5,741			1,018			1,198			2,188			2,916
NGL and refined products transportation and services:
Revenues from external customers	2,271			2,845			7,340			7,467			1,666			2,356			3,784			5,069
Intersegment revenues	607			218			1,181			710			453			256			1,050			574
	2,878			3,063			8,521			8,177			2,119			2,612			4,834			5,643
Crude oil transportation and services:
Revenues from external customers	4,453			4,422			13,685			12,942			1,811			5,012			6,024			9,179
Intersegment revenues	—			16			—			44			28			34			28			53
	4,453			4,438			13,685			12,986			1,839			5,046			6,052			9,232
Investment in Sunoco LP:
Revenues from external customers	4,328			4,760			12,494			13,114			2,043			4,474			5,303			8,166
Intersegment revenues	3			1			4			3			37			1			49			1
	4,331			4,761			12,498			13,117			2,080			4,475			5,352			8,167
Investment in USAC:
Revenues from external customers	169			166			505			331			166			169			342			336
Intersegment revenues	6			3			15			5			3			5			6			9
	175			169			520			336			169			174			348			345
All other:
Revenues from external customers	420			498			1,196			1,491			356			371			720			829
Intersegment revenues	21			27			80			108			136			20			285			59
	441			525			1,276			1,599			492			391			1,005			888
Eliminations	(1,606		)	(2,062		)	(4,358		)	(5,239		)	(1,340		)	(1,277		)	(2,832		)	(2,805		)
Total revenues	$	13,495		$	14,514		$	40,493		$	40,514		$	7,338		$	13,877		$	18,965		$	26,998

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	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2020			2019*			2020			2019*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	235		$	221		$	777		$	621		$	187		$	290		$	427		$	542
Interstate transportation and storage	442			459			1,358			1,200			403			460			807			916
Midstream	411			434			1,205			1,225			367			412			750			794
NGL and refined products transportation and services	667			498			1,923			1,410			674			644			1,337			1,256
Crude oil transportation and services	700			682			2,257			1,694			519			752			1,110			1,496
Investment in Sunoco LP	192			208			497			457			182			152			391			305
Investment in USAC	104			90			310			185			105			105			211			206
All other	37			(6		)	83			69			4			13			46			46
Total	2,788			2,586			8,410			6,861			2,441			2,828			5,079			5,561
Depreciation, depletion and amortization	(782		)	(747		)	(2,334		)	(2,100		)	(934		)	(781		)	(1,799		)	(1,552		)
Interest expense, net of capitalized interest	(575		)	(446		)	(1,680		)	(1,246		)
Interest expense, net of interest capitalized													(578		)	(578		)	(1,178		)	(1,105		)
Impairment losses	(12		)	—			(62		)	—			(4		)	—			(1,329		)	(50		)
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Losses on interest rate derivatives													(3		)	(122		)	(332		)	(196		)
Non-cash compensation expense	(27		)	(27		)	(85		)	(82		)	(41		)	(29		)	(63		)	(58		)
Unrealized gains (losses) on commodity risk management activities	64			97			90			(255		)	(48		)	(23		)	3			26
Losses on extinguishments of debt	—			—			(2		)	(109		)	—			—			(59		)	(2		)
Inventory valuation adjustments	(26		)	(7		)	71			50
Inventory valuation adjustments (Sunoco LP)													90			4			(137		)	97
Adjusted EBITDA related to unconsolidated affiliates	(161		)	(179		)	(470		)	(503		)	(157		)	(163		)	(311		)	(309		)
Equity in earnings of unconsolidated affiliates	82			87			224			258			85			77			78			142
Adjusted EBITDA related to discontinued operations	—			—			—			25
Other, net	103			32			211			58			(34		)	104			(20		)	108
Income from continuing operations before income tax expense	1,279			1,441			4,002			3,074
Income tax (expense) benefit from continuing operations	(55		)	52			(216		)	(7		)
Income from continuing operations	1,224			1,493			3,786			3,067
Loss from discontinued operations, net of income taxes	—			(2		)	—			(265		)
Net income	$	1,224		$	1,491		$	3,786		$	2,802
Income (loss) before income tax expense													817			1,317			(68		)	2,662
Income tax expense													(98		)	(35		)	(127		)	(161		)
Net income (loss)													$	719		$	1,282		$	(195	)	$	2,501



	June 30, 2020		December 31, 2019*
Segment assets:
Intrastate transportation and storage	$	6,972	$	6,648
Interstate transportation and storage	17,413		18,111
Midstream	19,132		20,332
NGL and refined products transportation and services	21,803		19,145
Crude oil transportation and services	21,481		22,933
Investment in Sunoco LP	4,985		5,438
Investment in USAC	3,058		3,730
All other	3,640		5,959
Total segment assets	$	98,484	$	102,296


~~16.~~	~~CONSOLIDATING GUARANTOR FINANCIAL INFORMATION~~

Sunoco Logistics Partners Operations L.P., a subsidiary of ETO, is the issuer of multiple series of senior notes that are guaranteed by ETO. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Operating, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting. The December 31, 2018 balance sheet has been updated to conform the prior period presentation to be consistent with the current period presentation.*As adjusted. See Note 1.

~~Table of Contents~~

~~The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows:~~

September 30, 2019
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents $ —
$ —
$ 207
$ —
$ 207
Accounts receivable, related parties 4,467
43,654
73,807
(121,704 ) 224
All other current assets —
—
6,724
—
6,724
Property, plant and equipment, net —
—
68,870
—
68,870
Investments in unconsolidated affiliates 56,270
14,838
3,065
(71,186 ) 2,987
All other assets 3,560
131
12,544
—
16,235
Total assets $ 64,297
$ 58,623
$ 165,217
$ (192,890 ) $ 95,247

Accounts payable, related parties $ 2,725
$ 40,512
$ 76,876
$ (120,090 ) $ 23
Other current liabilities 654
140
6,205
—
6,999
Non-current liabilities 31,260
7,603
13,751
—
52,614
Noncontrolling interests —
—
7,974
—
7,974
Total partners’ capital 29,658
10,368
60,411
(72,800 ) 27,637
Total liabilities and equity $ 64,297
$ 58,623
$ 165,217
$ (192,890 ) $ 95,247

December 31, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents $ —
$ —
$ 418
$ —
$ 418
Accounts receivable, related parties 4,070
36,889
67,110
(107,893 ) 176
All other current assets —
—
6,226
—
6,226
Property, plant and equipment, net —
—
66,655
—
66,655
Investments in unconsolidated affiliates 51,876
13,090
2,636
(64,966 ) 2,636
All other assets 12
75
12,244
—
12,331
Total assets $ 55,958
$ 50,054
$ 155,289
$ (172,859 ) $ 88,442

Accounts payable, related parties $ 3,031
$ 33,414
$ 72,055
$ (108,381 ) $ 119
Other current liabilities 399
103
8,676
—
9,178
Non-current liabilities 24,787
7,605
10,132
—
42,524
Noncontrolling interests —
—
7,903
—
7,903
Total partners’ capital 27,741
8,932
56,523
(64,478 ) 28,718
Total liabilities and equity $ 55,958
$ 50,054
$ 155,289
$ (172,859 ) $ 88,442

~~Table of Contents~~

Three Months Ended September 30, 2019
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues $ —
$ —
$ 13,495
$ —
$ 13,495
Operating costs, expenses, and other —
—
11,661
—
11,661
Operating income —
—
1,834
—
1,834
Interest expense, net of capitalized interest (412 ) (151 ) (12 ) —
(575 )
Equity in earnings of unconsolidated affiliates 1,443
519
82
(1,962 ) 82
Gains on interest rate derivatives (175 ) —
—
—
(175 )
Other, net 93
3
17
—
113
Income before income tax expense 949
371
1,921
(1,962 ) 1,279
Income tax expense —
—
55
—
55
Net income 949
371
1,866
(1,962 ) 1,224
Less: Net income attributable to noncontrolling interests —
—
261
—
261
Less: Net income attributable to redeemable noncontrolling interests —
—
12
—
12
Net income attributable to partners $ 949
$ 371
$ 1,593
$ (1,962 ) $ 951

Other comprehensive loss $ —
$ —
$ (7 ) $ —
$ (7 )
Comprehensive income 949
371
1,859
(1,962 ) 1,217
Less: Comprehensive income attributable to noncontrolling interests —
—
261
—
261
Less: Comprehensive income attributable to redeemable noncontrolling interests —
—
12
—
12
Comprehensive income attributable to partners $ 949
$ 371
$ 1,586
$ (1,962 ) $ 944

~~Table of Contents~~

Three Months Ended September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues $ —
$ —
$ 14,514
$ —
$ 14,514
Operating costs, expenses, and other —
—
12,799
—
12,799
Operating income —
—
1,715
—
1,715
Interest expense, net of capitalized interest (303 ) (55 ) (88 ) —
(446 )
Equity in earnings of unconsolidated affiliates 1,394
501
87
(1,895 ) 87
Gains on interest rate derivatives 45
—
—
—
45
Other, net —
—
40
—
40
Income from continuing operations before income tax benefit 1,136
446
1,754
(1,895 ) 1,441
Income tax benefit from continuing operations —
—
(52 ) —
(52 )
Income from continuing operations 1,136
446
1,806
(1,895 ) 1,493
Loss from discontinued operations, net of income taxes —
—
(2 ) —
(2 )
Net income 1,136
446
1,804
(1,895 ) 1,491
Less: Net income attributable to noncontrolling interests —
—
223
—
223
Less: Net income attributable to predecessor equity —
—
133
—
133
Net income attributable to partners $ 1,136
$ 446
$ 1,448
$ (1,895 ) $ 1,135

Other comprehensive income $ —
$ —
$ 4
$ —
$ 4
Comprehensive income 1,136
446
1,808
(1,895 ) 1,495
Less: Comprehensive income attributable to noncontrolling interests —
—
223
—
223
Less: Comprehensive income attributable to predecessor equity —
—
133
—
133
Comprehensive income attributable to partners $ 1,136
$ 446
$ 1,452
$ (1,895 ) $ 1,139

~~Table of Contents~~

Nine Months Ended September 30, 2019
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues $ —
$ —
$ 40,493
$ —
$ 40,493
Operating costs, expenses, and other —
—
34,904
—
34,904
Operating income —
—
5,589
—
5,589
Interest expense, net of capitalized interest (1,190 ) (280 ) (210 ) —
(1,680 )
Equity in earnings of unconsolidated affiliates 4,292
1,638
224
(5,930 ) 224
Losses on extinguishments of debt —
—
(2 ) —
(2 )
Gains on interest rate derivatives (371 ) —
—
—
(371 )
Other, net 233
3
6
—
242
Income before income tax benefit 2,964
1,361
5,607
(5,930 ) 4,002
Income tax expense —
—
216
—
216
Net income 2,964
1,361
5,391
(5,930 ) 3,786
Less: Net income attributable to noncontrolling interests —
—
783
—
783
Less: Net income attributable to redeemable noncontrolling interests —
—
38
—
38
Net income attributable to partners $ 2,964
$ 1,361
$ 4,570
$ (5,930 ) $ 2,965

Other comprehensive income $ —
$ —
$ 2
$ —
$ 2
Comprehensive income 2,964
1,361
5,393
(5,930 ) 3,788
Less: Comprehensive income attributable to noncontrolling interests —
—
783
—
783
Less: Comprehensive income attributable to redeemable noncontrolling interests

38

38
Comprehensive income attributable to partners $ 2,964
$ 1,361
$ 4,572
$ (5,930 ) $ 2,967

~~Table of Contents~~

Nine Months Ended September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues $ —
$ —
$ 40,514
$ —
$ 40,514
Operating costs, expenses, and other —
—
36,556
—
36,556
Operating income —
—
3,958
—
3,958
Interest expense, net of capitalized interest (870 ) (137 ) (239 ) —
(1,246 )
Equity in earnings of unconsolidated affiliates 3,036
827
258
(3,863 ) 258
Losses on extinguishments of debt —
—
(109 ) —
(109 )
Gains on interest rate derivatives 117
—
—
—
117
Other, net —
—
96
—
96
Income from continuing operations before income tax expense 2,283
690
3,964
(3,863 ) 3,074
Income tax expense from continuing operations —
—
7
—
7
Income from continuing operations 2,283
690
3,957
(3,863 ) 3,067
Loss from discontinued operations, net of income taxes —
—
(265 ) —
(265 )
Net income 2,283
690
3,692
(3,863 ) 2,802
Less: Net income attributable to noncontrolling interests —
—
557
—
557
Less: Net loss attributable to predecessor equity

(37 )

(37 )
Net income attributable to partners $ 2,283
$ 690
$ 3,172
$ (3,863 ) $ 2,282

Other comprehensive income $ —
$ —
$ 7
$ —
$ 7
Comprehensive income 2,283
690
3,699
(3,863 ) 2,809
Less: Comprehensive income attributable to noncontrolling interests —
—
557
—
557
Less: Comprehensive loss attributable to predecessor equity

(37 )

(37 )
Comprehensive income attributable to partners $ 2,283
$ 690
$ 3,179
$ (3,863 ) $ 2,289

Nine Months Ended September 30, 2019
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows provided by operating activities $ 1,854
$ 2,620
$ 4,613
$ (3,025 ) $ 6,062
Cash flows provided by (used in) investing activities (482 ) (2,620 ) (4,346 ) 3,025
(4,423 )
Cash flows provided by (used in) financing activities (1,372 ) —
(478 ) —
(1,850 )
Change in cash —
—
(211 ) —
(211 )
Cash at beginning of period —
—
418
—
418
Cash at end of period $ —
$ —
$ 207
$ —
$ 207

~~Table of Contents~~

Nine Months Ended September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows provided by operating activities $ 2,753
$ 579
$ 4,256
$ (2,078 ) $ 5,510
Cash flows used in investing activities (834 ) (579 ) (5,178 ) 2,078
(4,513 )
Cash flows used in financing activities (1,919 ) —
(1,754 ) —
(3,673 )
Net increase in cash and cash equivalents of discontinued operations

2,738

2,738
Change in cash —
—
62
—
62
Cash at beginning of period —
—
335
—
335
Cash at end of period $ —
$ —
$ 397
$ —
$ 397

4936

Table of Contents

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

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts 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, ~~2018~~2019 filed with the SEC on February ~~22, 2019.~~21, 2020. 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, ~~2018~~2019 filed with the SEC on February ~~22, 2019.~~21, 2020, “Part II - Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 11, 2020 and “Part II - Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q. Additional information on forward-looking statements is discussed below in “Forward-Looking Statements.”

References to “we,” “us,” “our,” the “Partnership” and “ETO” shall mean Energy Transfer Operating, L.P. and its subsidiaries.

RECENT DEVELOPMENTS

~~ETO Term Loan~~COVID-19

~~On October 17, 2019, ETO entered into a term loan credit agreement providing~~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 ~~a $2 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes~~many individuals to substantially restrict daily activities and for ~~general partnership purposes. The term loan agreement will be unsecured~~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 ~~will be guaranteed by~~ our ~~subsidiary, Sunoco Logistics Partners Operations L.P.~~

Borrowings under the term loan agreement will bear interest at a eurodollar rate or a base rate, at ETO’s option, plus an applicable margin. The applicable margin and applicable rate used in connection with the interest rates are based on the credit ratings assignedemployees as "essential critical infrastructure workers" pursuant to the ~~senior, unsecured, non-credit enhanced long-term debt~~Department of ~~ETO.~~ 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.

~~Acquisition~~ET Contribution of SemGroup ~~by ET~~Assets to ETO

On ~~September 16,~~December 5, 2019, ET ~~entered into a definitive merger agreement to acquire SemGroup in a unit~~completed the acquisition of SemGroup. During the first and ~~cash transaction. Total consideration, including the assumption~~second quarters of ~~debt, is approximately $5 billion, based on the closing price of~~2020, ET common units on September 13, 2019. The transaction is expected to close in late 2019 or early 2020, subject to the approval by SemGroup’s stockholders and other customary regulatory approvals. ET expects to contribute thecontributed certain SemGroup assets to ~~the~~ETO through sale and contribution transactions. The Partnership and SemGroup are under common control by ET subsequent to ~~closing~~ET’s acquisition of SemGroup; therefore, these transactions were accounted for as reorganizations of entities under common control. Accordingly, beginning with the ~~acquisition.~~

~~J.C. Nolan~~

~~On July 1, 2019, ETO entered into a joint venture with Sunoco LP, under which ETO will operate a pipeline that will transport diesel fuel from Hebert, Texas~~quarter ending March 31, 2020, the Partnership’s consolidated financial statements have been retrospectively adjusted to ~~a terminal near Midland, Texas on behalf~~reflect the consolidation of the ~~joint venture. The diesel fuel pipeline had an initial capacity of 30,000 barrels per day and was successfully commissioned in August 2019.~~contributed SemGroup businesses beginning December 5, 2019 (the date ET acquired SemGroup).

ETO Series EF and Series G Preferred Units Issuance

~~In April 2019,~~On January 22, 2020, ETO issued ~~32 million~~500,000 of its ~~7.600%~~ Series EF Preferred Units at a price of ~~$25~~$1,000 per unit ~~including 4 million~~and 1,100,000 of its Series EG Preferred Units ~~pursuant to the underwriters’ exercise~~at a price of their option to purchase additional preferred units. The total gross proceeds from the Series E Preferred Unit issuance were $800 million, including $100 million from the underwriters’ exercise of their option.$1,000 per unit. The net proceeds were used to repay amounts outstanding under ~~ETO’s Five-Year Credit Facility~~ETO's revolving credit facility and for general partnership purposes.

~~ET-ETO~~ETO January 2020 Senior Notes ~~Exchange~~Offering and Redemption

~~In March 2019,~~On January 22, 2020, ETO ~~issued approximately $4.21~~completed 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 of the Partnership’s 3.750% Senior Notes due 2030 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 ~~notes to settle and exchange approximately 97%~~unsecured basis.

Using proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of ~~ET’s outstanding senior notes. In connection with this exchange, ETO issued~~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~~Senior Notes due October 15, 2020, ~~$995 million aggregate principal amount of 4.25% senior notes due 2023, $1.13 billion aggregate principal amount of 5.875% senior notes due 2024 and $956~~its $250 million aggregate principal amount of 5.50% ~~senior notes due 2027.~~

~~ETO~~ Senior Notes ~~Offering and Redemption~~

~~In January 2019, ETO issued $750~~due February 15, 2020, ET’s $52 million aggregate principal amount of ~~4.50% senior notes~~7.50% Senior Notes due ~~2024, $1.50 billion~~October 15, 2020 and Transwestern’s $175 million aggregate principal amount of ~~5.25% senior notes~~5.36% Senior Notes due 2029 and $1.75 billion aggregate principal amount of 6.25% senior notes due 2049. The $3.96 billion net proceeds from the offering were used to repay in full ET’s outstanding senior secured term loan, to redeemDecember 9, 2020.

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~~outstanding senior notes at maturity,~~Lake Charles LNG

On March 30, 2020, Shell Royal Dutch Plc announced that it would not proceed with a proposed equity interest in the Lake Charles LNG liquefaction project due to ~~repay a portion~~adverse market factors affecting Shell's business and its desire to preserve cash in light of the ~~borrowings under~~current environment. We intend to continue to develop the ~~Partnership’s revolving credit facility~~project, possibly in conjunction with one or more equity partners, and ~~for general partnership purposes.~~

~~Panhandle Senior Notes Redemption~~

~~In June 2019, Panhandle’s $150~~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 ~~aggregate principal amount~~tonnes per annum of ~~8.125% senior notes matured~~LNG capacity) to two trains (11.0 million tonnes per annum). The project is fully permitted by federal, state and ~~were repaid with borrowings under an affiliate loan agreement with ETO.~~

~~Bakken Senior Notes Offering~~

In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued $650 million aggregate principal amount of 3.625% senior notes due 2022, $1.00 billion aggregate principal amount of 3.90% senior notes due 2024local authorities, has all necessary export licenses and ~~$850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds~~benefits from the ~~offering were used~~infrastructure related to ~~repay in full all amounts outstanding on~~ the ~~Bakken credit~~existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the ~~facility was terminated.~~

~~Sunoco LP Senior Notes Offering~~

~~In March 2019, Sunoco LP issued $600 million aggregate principal amount~~advanced state of ~~6.00% senior notes due 2027~~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 a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identicalsecuring equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms.

~~USAC Senior Notes Offering~~

Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective January 2018, the 2017 Tax and Jobs Act (the ~~“Tax Act”~~"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”~~Statement") stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not ~~“double recover”~~"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’~~investors' income tax costs. In light of the rehearing order, the impacts of the ~~FERC’s~~FERC's policy on the treatment of income taxes may have on the rates ETO can charge for the FERC regulated transportation services are 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 of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, 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.

~~Also included in~~In March 2019, following the ~~March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation~~decision of the ~~Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018,~~D.C. Circuit in Emera Maine v. Federal Energy Regulatory Commission, the FERC issued a ~~Final Rule adopting procedures that are generally~~Notice of Inquiry regarding its policy for determining return on equity ("ROE"). The FERC specifically sought information and stakeholder views to help the ~~same~~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. The FERC has not taken any further action with respect to the Notice of Inquiry as ~~proposed~~of this time, and therefore we cannot predict what effect, if any, such development could have on our cost-of-service rates in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC regulated natural gas pipeline select one of four options to address changes to the pipeline’s

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revenue requirements as a result of the tax reductions: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates to reflect the reduced tax rates, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. For the limited NGA Section 4 option, the FERC clarified that, notwithstanding the Revised Policy Statement, a pipeline organized as a master limited partnership does not need to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Trunkline, ETC Tiger Pipeline, LLC and Panhandle filed their respective FERC Form No. 501-Gs on October 11, 2018. FEP, Lake Charles LNG and certain other operating subsidiaries filed their respective FERC Form No. 501-Gs on or about November 8, 2018, and Rover, FGT, Transwestern and MEP filed their respective FERC Form No. 501-Gs on or about December 6, 2018. 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 to determine whether the rates currently 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 NGA Section 4 rate case on August 30, 2019.

By order issued October 1, 2019, the Section 5 and Section 4 cases were consolidated. An initial decision is expected to be issued in the first quarter of 2021. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. Sea Robin Pipeline Company filed a Section 4 rate case on November 30, 2018. A procedural schedule was ordered with a hearing date in the 4th quarter of 2019. Sea Robin Pipeline Company has reached a settlement of this proceeding, with a settlement filed July 22, 2019. The settlement was approved by the FERC by order dated October 17, 2019.

Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, 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, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also 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,

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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 any final regulations that may result 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 ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, 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.

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 ~~may~~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 on or before July 25, 2018. 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, or PPI. 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 plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every ~~year. Most of the adjustments are effective~~ July ~~1 of each year.~~1. With respect to ~~common carrier~~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 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

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Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while 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 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 service based rates in the 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/or crude oil caused by the COVID-19 pandemic and a continuation of low WTI crude oil prices may result in the 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 remained comparatively low in recent months as associated gas from shale oil resources has provided additional supply to the market. Meanwhile, crude oil prices saw a sharp declines 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 suppressed for the foreseeable future. With respect to natural gas markets, a relatively more moderate decrease in demand, coupled with anticipated decreases in gas production associated with wells drilled to produce crude oil, have counterbalanced softness in pricing. The overall outlook for our midstream services will depend, in part, on the timing and extent of recovery in the commodity markets.

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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 this case, 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 $600 million and reduced planned operating expenses by approximately $400 million. While current market volatility makes the near-term unpredictable, we believe that overall the long-term demand for our services will continue given the essential nature of the midstream natural gas, NGLs, refined products and crude oil business, 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 half 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.

Results of Operations

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 ~~Energy Transfer Merger in October 2018 resulted in~~first quarter of 2020, the ~~retrospective adjustment~~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 ~~Partnership’s consolidated financial statements to reflect consolidation beginning January 1, 2018 of Sunoco LP and Lake Charles LNG and April 2, 2018 for USAC.~~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,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019*			Change			2020			2019*			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	235		$	221		$	14		$	777		$	621		$	156		$	187		$	290		$	(103	)	$	427		$	542		$	(115	)
Interstate transportation and storage	442			459			(17		)	1,358			1,200			158			403			460			(57		)	807			916			(109		)
Midstream	411			434			(23		)	1,205			1,225			(20		)	367			412			(45		)	750			794			(44		)
NGL and refined products transportation and services	667			498			169			1,923			1,410			513			674			644			30			1,337			1,256			81
Crude oil transportation and services	700			682			18			2,257			1,694			563			519			752			(233		)	1,110			1,496			(386		)
Investment in Sunoco LP	192			208			(16		)	497			457			40			182			152			30			391			305			86
Investment in USAC	104			90			14			310			185			125			105			105			—			211			206			5
All other	37			(6		)	43			83			69			14			4			13			(9		)	46			46			—
Adjusted EBITDA (consolidated)	2,788			2,586			202			8,410			6,861			1,549			2,441			2,828			(387		)	5,079			5,561			(482		)
Depreciation, depletion and amortization	(782		)	(747		)	(35		)	(2,334		)	(2,100		)	(234		)	(934		)	(781		)	(153		)	(1,799		)	(1,552		)	(247		)
Interest expense, net of capitalized interest	(575		)	(446		)	(129		)	(1,680		)	(1,246		)	(434		)
Interest expense, net of interest capitalized																			(578		)	(578		)	—			(1,178		)	(1,105		)	(73		)
Impairment losses	(12		)	—			(12		)	(62		)	—			(62		)	(4		)	—			(4		)	(1,329		)	(50		)	(1,279		)
Gains (losses) on interest rate derivatives	(175		)	45			(220		)	(371		)	117			(488		)
Losses on interest rate derivatives																			(3		)	(122		)	119			(332		)	(196		)	(136		)
Non-cash compensation expense	(27		)	(27		)	—			(85		)	(82		)	(3		)	(41		)	(29		)	(12		)	(63		)	(58		)	(5		)
Unrealized gains (losses) on commodity risk management activities	64			97			(33		)	90			(255		)	345			(48		)	(23		)	(25		)	3			26			(23		)
Losses on extinguishments of debt	—			—			—			(2		)	(109		)	107			—			—			—			(59		)	(2		)	(57		)
Inventory valuation adjustments	(26		)	(7		)	(19		)	71			50			21
Inventory valuation adjustments (Sunoco LP)																			90			4			86			(137		)	97			(234		)
Adjusted EBITDA related to unconsolidated affiliates	(161		)	(179		)	18			(470		)	(503		)	33			(157		)	(163		)	6			(311		)	(309		)	(2		)
Equity in earnings of unconsolidated affiliates	82			87			(5		)	224			258			(34		)	85			77			8			78			142			(64		)
Adjusted EBITDA related to discontinued operations	—			—			—			—			25			(25		)
Other, net	103			32			71			211			58			153			(34		)	104			(138		)	(20		)	108			(128		)
Income from continuing operations before income tax expense	1,279			1,441			(162		)	4,002			3,074			928
Income tax (expense) benefit from continuing operations	(55		)	52			(107		)	(216		)	(7		)	(209		)
Income from continuing operations	1,224			1,493			(269		)	3,786			3,067			719
Loss from discontinued operations, net of income taxes	—			(2		)	2			—			(265		)	265
Net income	$	1,224		$	1,491		$	(267	)	$	3,786		$	2,802		$	984
Income (loss) before income tax expense																			817			1,317			(500		)	(68		)	2,662			(2,730		)
Income tax expense																			(98		)	(35		)	(63		)	(127		)	(161		)	34
Net income (loss)																			$	719		$	1,282		$	(563	)	$	(195	)	$	2,501		$	(2,696	)

*As adjusted.

Adjusted EBITDA (consolidated). For the three and six months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year, Adjusted EBITDA ~~increased $202 million, or 8%. The increase was~~decreased 14% and 9%, respectively, primarily due to the ~~impact~~impacts of ~~multiple revenue-generating assets being placed in service~~lower volumes and ~~recent acquisitions, as well as increased demand for services on existing assets. The impact~~market prices among several of ~~new assets included the Mariner East 2 pipeline (a $50~~our core operating segments; these decreases were partially offset by net increases of approximately $150 million ~~impact (net of $27~~and $290 million, in fees from our marketing affiliate) to the NGL and refined products transportation and services and midstream segments), our sixth fractionator (a $25 million impact to the NGL and refined products transportation and services segment) and higher throughput volumes from the Permian region on our Texas NGL pipeline (a $80 million impact to the NGL and refined products and transportation services segment). The remainder of the increaserespectively, in Adjusted EBITDA ~~was primarily due to stronger demand on existing assets.~~

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~~For the nine months ended September 30, 2019 compared to the same period last year, Adjusted EBITDA increased $1.55 billion, or 23%.~~ ~~The increase was primarily due to the impact of multiple revenue-generating~~from recent acquisitions and assets ~~being~~ placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets included the Mariner East 2 pipeline (a $131 million impact (net of $44 million in fees from our marketing affiliate) to the NGL and refined products transportation and services segment), our fifth and sixth fractionators (a $114 million impact to the NGL and refined products transportation and services segment), and the Rover pipeline (a $108 million impact to the interstate transportation and storage segment). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, including higher throughput volumes from the Permian region on our Texas NGL and crude pipelines (a $175 million impact to the NGL and refined products transportation and services segment and a $355 million impact to the crude oil transportation and services segment) and higher throughput on the Bakken pipeline (a $188 million impact to the crude oil transportation and services segment). The increase in Adjusted EBITDA also reflected the impact of realized gains from pipeline optimization activity (an increase of $96 million to the midstream segment), as well as an increase of $125 million in our investment in USAC segment primarily due to the consolidation of USAC beginning April 2, 2018.service.

Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.

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

Table of ~~USAC on April 2, 2018.~~Contents

Interest Expense, Net of ~~Capitalized Interest.~~Interest Capitalized. Interest expense, net of interest capitalized, ~~interest,~~ increased for the ~~three and nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same periods last year primarily due to the following:

increases of $112 million and $366 million, respectively, recognized by the Partnership primarily due to to increases in long-term debt from ETO senior note issuances, including the ET-ETO senior notes exchange in March 2019. The increases also reflect higher interest rates on floating rate borrowings, as well as the impact of reductions of $10 million and $77 million, respectively, in capitalized interest due to the completion of major projects in 2018;


•	an increase of $67 million recognized by the Partnership primarily attributable to higher debt balances following the March 2019 ET-ETO notes exchange and the December 2019 SemGroup acquisition, partially offset by lower borrowing costs on both recently refinanced debt and floating rate debt and higher capitalized interest;

•

an increase of $3 million for USAC for the six months ended June 30, 2020 compared to the six months ended June 30, 2019 was primarily attributable to a full six months of interest expense incurred in the current period on its senior notes issued in March 2019, which were used to reduce borrowings under the credit agreement, partially offset by reduced borrowings and lower weighted average interest rates under the credit agreement; and

an increase of $7$3 million for Sunoco LP for the ~~three~~six months ended ~~September~~June 30, ~~2019 recognized by USAC primarily due to its senior notes issuance in March 2019 and an increase of $43 million for the nine months ended September 30, 2019 primarily due~~2020 compared to the ~~consolidation of USAC beginning April 2, 2018, the date ET obtained control of USAC; and~~

~~increases of $10 million and $25 million, respectively, recognized by Sunoco LP~~same period last year primarily related to an increase in Sunoco LP’s total long-term debt.

Impairment Losses. ~~Due to a decrease in~~During the ~~demand for storage on the Partnership’s interstate transportation and storage segment Southwest Gas natural gas storage assets,~~three months ended March 31, 2020, the Partnership performed an interim impairment test on ~~the assets of Southwest Gas during the three months ended September 30, 2019.~~certain reporting units within midstream, interstate, crude, NGL and all other operations. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of ~~$12~~$483 million related to ~~Southwest Gas,~~our Arklatex and South Texas operations 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. No other impairments~~flows as a result of the ~~Partnership’s other assets were identified.~~overall market demand decline. In addition, ~~for~~USAC recognized a goodwill impairment of $619 million, during the ~~nine~~three months ended ~~September 30,~~March 31, 2020, which is included in the Partnership’s consolidated results of operations. During the three months ended March 31, 2019, ~~Sunoco LP recognized an asset~~USAC recorded a $3 million impairment of ~~$47~~compression equipment as a result of its evaluations of the future deployment of USAC’s idle fleet under then-current market conditions. USAC recorded a $4 million ~~on assets held for sale related to its Fulton, New York ethanol plant, and USAC recognized an asset~~ impairment of ~~$3 million related to certain~~ compression ~~equipment.~~equipment during the three months ended June 30, 2020 as a result of its evaluations of the future deployment of its idle fleet under current market conditions.

~~Gains (Losses)~~Losses on Interest Rate Derivatives. Losses on interest rate derivatives during the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in “Segment Operating Results” below.

Losses on Extinguishments of Debt. ~~Losses on extinguishments of debt for~~During the ~~nine~~three and six months ended ~~September~~June 30, ~~2018 resulted from Sunoco LP’s~~2020, amounts were related to ETO senior ~~note and term loan~~notes redemption in January ~~2018.~~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.

~~Adjusted EBITDA Related to Discontinued Operations.~~ ~~Amounts were related to the operations of Sunoco LP’s retail business that were disposed of in January 2018.~~

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Other, net. Other, net primarily includes ~~a gain of $55 million in connection with~~ the ~~merger of UGI and AmeriGas and~~ interest income related to the ET-ETO Promissory Notes, as well as amortization of regulatory assets and other income and expense amounts.

Income Tax ~~(Expense) Benefit.~~Expense. For the three months ended ~~September~~June 30, ~~2019~~2020 compared to the same period in the prior year, income tax expense increased due to the recognition of a favorable state tax rate change in the prior period. For the nine months ended September 30, 2019 compared to the same period last year, income tax expense increased primarily due to the recognition of a favorable state tax rate change in the prior period and an increase in income before tax expensehigher earnings at our corporate subsidiaries in the current period. For the six months ended June 30, 2020 compared to the same period in the prior year, income tax expense decreased due to the recognition of a taxable gain on the sale of assets at our corporate subsidiaries in the prior period.

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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 June 30,								Six Months Ended June 30,
	2019		2018		Change			2019		2018		Change			2020			2019		Change			2020			2019		Change
Equity in earnings of unconsolidated affiliates:
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	44	$	42	$	2		$	115	$	102	$	13		$	42		$	39	$	3		$	77		$	71	$	6
FEP	15		14		1			43		41		2			18			14		4			(52		)	28		(80		)
MEP	1		7		(6		)	15		24		(9		)	(2		)	7		(9		)	(2		)	14		(16		)
White Cliffs															9			—		9			17			—		17
Other	22		24		(2		)	51		91		(40		)	18			17		1			38			29		9
Total equity in earnings of unconsolidated affiliates	$	82	$	87	$	(5	)	$	224	$	258	$	(34	)
Total equity in earnings (losses) of unconsolidated affiliates															$	85		$	77	$	8		$	78		$	142	$	(64	)

Adjusted EBITDA related to unconsolidated affiliates:
Adjusted EBITDA related to unconsolidated affiliates⁽¹⁾:
Citrus	$	92	$	96	$	(4	)	$	260	$	256	$	4		$	89		$	87	$	2		$	168		$	168	$	—
FEP	19		19		—			56		56		—			19			18		1			38			37		1
MEP	13		20		(7		)	52		62		(10		)	7			20		(13		)	15			39		(24		)
White Cliffs															13			—		13			27			—		27
Other	37		44		(7		)	102		129		(27		)	29			38		(9		)	63			65		(2		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	161	$	179	$	(18	)	$	470	$	503	$	(33	)	$	157		$	163	$	(6	)	$	311		$	309	$	2

Distributions received from unconsolidated affiliates:
Citrus	$	54	$	52	$	2		$	128	$	125	$	3		$	58		$	39	$	19		$	107		$	74	$	33
FEP	20		18		2			53		50		3			17			16		1			35			33		2
MEP	7		9		(2		)	33		40		(7		)	7			15		(8		)	18			26		(8		)
White Cliffs															10			—		10			23			—		23
Other	22		34		(12		)	80		76		4			20			42		(22		)	39			58		(19		)
Total distributions received from unconsolidated affiliates	$	103	$	113	$	(10	)	$	294	$	291	$	3		$	112		$	112	$	—		$	222		$	191	$	31


⁽¹⁾	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.

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.

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•	Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

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•	Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. 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.

Intrastate Transportation and Storage


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
Natural gas transported (BBtu/d)	12,560			12,146			414			12,221			10,592			1,629			12,921			12,115			806			13,028			12,049			979
Withdrawals from storage natural gas inventory (BBtu)	—			—			—			—			17,703			(17,703		)	(1,910		)	—			(1,910		)	5,065			—			5,065
Revenues	$	764		$	922		$	(158	)	$	2,385		$	2,610		$	(225	)	$	516		$	765		$	(249	)	$	1,109		$	1,621		$	(512	)
Cost of products sold	501			638			(137		)	1,473			1,888			(415		)	248			400			(152		)	551			972			(421		)
Segment margin	263			284			(21		)	912			722			190			268			365			(97		)	558			649			(91		)
Unrealized (gains) losses on commodity risk management activities	19			(12		)	31			3			33			(30		)
Unrealized gains on commodity risk management activities																			(33		)	(26		)	(7		)	(39		)	(16		)	(23		)
Operating expenses, excluding non-cash compensation expense	(48		)	(51		)	3			(137		)	(141		)	4			(48		)	(47		)	(1		)	(89		)	(89		)	—
Selling, general and administrative expenses, excluding non-cash compensation expense	(7		)	(7		)	—			(20		)	(20		)	—			(6		)	(7		)	1			(15		)	(13		)	(2		)
Adjusted EBITDA related to unconsolidated affiliates	7			6			1			18			26			(8		)	6			5			1			12			11			1
Other	1			1			—			1			1			—
Segment Adjusted EBITDA	$	235		$	221		$	14		$	777		$	621		$	156		$	187		$	290		$	(103	)	$	427		$	542		$	(115	)

Volumes. For the three and six months ended ~~September~~June 30, ~~2019~~2020 compared to the same ~~period~~periods last year, transported volumes increased primarily due to increased utilization of our Texas pipelines.

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For the nine months ended compared to the same period last year, transported volumes increased primarily due to the impact of reflecting RIGS as a consolidated subsidiary beginning in April 2018 and the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.

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 June 30,							Six Months Ended June 30,
	2019			2018		Change			2019			2018			Change			2020		2019		Change			2020		2019		Change
Transportation fees	$	150		$	141	$	9		$	452		$	392		$	60		$	148	$	148	$	—		$	309	$	302	$	7
Natural gas sales and other (excluding unrealized gains and losses)	112			110		2			405			309			96			68		173		(105		)	156		293		(137		)
Retained fuel revenues (excluding unrealized gains and losses)	14			16		(2		)	37			42			(5		)	10		12		(2		)	19		23		(4		)
Storage margin (excluding unrealized gains and losses)	6			5		1			21			12			9			9		6		3			35		15		20
Unrealized gains (losses) on commodity risk management activities	(19		)	12		(31		)	(3		)	(33		)	30
Unrealized gains on commodity risk management activities																		33		26		7			39		16		23
Total segment margin	$	263		$	284	$	(21	)	$	912		$	722		$	190		$	268	$	365	$	(97	)	$	558	$	649	$	(91	)

Segment Adjusted EBITDA. For the three months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation ~~and storage~~ segment ~~increased~~decreased due to the net impacts of the following:


•	~~an increase~~a decrease of $9$105 million in ~~transportation fees~~realized natural gas sales and other primarily due to ~~increased utilization of our Texas pipelines;~~lower realized gains from pipeline optimization activity; and

~~an increase of $2 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and~~


•	an increase of $1 million in ~~realized storage margin~~operating expenses primarily due to higher ~~storage fees;~~maintenance project costs and higher cost of fuel consumption; partially offset by


•	~~a decrease of $2 million in retained fuel revenue primarily due to lower gas prices.~~ an increase of $3 million in realized storage margin primarily due to higher storage optimization and fees.

Segment Adjusted EBITDA. For the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation ~~and storage~~ segment ~~increased~~decreased due to the net impacts of the following:


•	~~an increase~~a decrease of ~~$96~~$137 million in realized natural gas sales and other primarily due to ~~higher~~lower realized gains from pipeline optimization activity;


•	~~an increase~~a decrease of ~~$36~~$4 million in ~~transportation fees, excluding the impact of consolidating RIGS as discussed below,~~retained fuel revenues primarily due to ~~new contracts, as well as the impact of the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;~~


•	~~a net increase of $11 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, retained fuel revenues~~lower gas prices; and ~~operating expenses of $24 million, $2 million, and $6 million, respectively, and a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates; and~~

•

an increase of $9$2 million in ~~realized storage margin~~selling, general and administrative expenses primarily due to ~~a realized adjustment to the Bammel storage inventory of $25 million in 2018, and~~ higher ~~storage fees, partially offset by a $13 million decrease primarily due to no physical withdrawals and a $5 million decrease in realized derivative gains;~~allocated corporate costs; partially offset by


•	~~a decrease~~an increase of $5$20 million in ~~retained fuel revenues~~realized storage margin primarily due to ~~lower natural gas prices.~~higher storage optimization;


•	an increase of $7 million in transportation fees primarily due to volume ramp-ups on the Red Bluff Express pipeline and new contracts; and

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 June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
Natural gas transported (BBtu/d)	11,407			10,155			1,252			11,254			9,029			2,225			10,152			10,825			(673		)	10,440			11,177			(737		)
Natural gas sold (BBtu/d)	17			18			(1		)	18			17			1			17			17			—			16			18			(2		)
Revenues	$	479		$	445		$	34		$	1,470		$	1,187		$	283		$	445		$	493		$	(48	)	$	909		$	991		$	(82	)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(141		)	(104		)	(37		)	(425		)	(312		)	(113		)	(139		)	(138		)	(1		)	(282		)	(284		)	2
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(17		)	(20		)	3			(49		)	(55		)	6			(16		)	(18		)	2			(37		)	(32		)	(5		)
Adjusted EBITDA related to unconsolidated affiliates	124			135			(11		)	368			374			(6		)	115			125			(10		)	221			244			(23		)
Other	(3		)	3			(6		)	(6		)	6			(12		)	(2		)	(2		)	—			(4		)	(3		)	(1		)
Segment Adjusted EBITDA	$	442		$	459		$	(17	)	$	1,358		$	1,200		$	158		$	403		$	460		$	(57	)	$	807		$	916		$	(109	)

Volumes. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same periods last year, transported volumes ~~reflected an increase~~decreased 0.7 Bcf/d primarily due to shut-ins of ~~1,252 BBtu/d and 2,225 BBtu/d, respectively, as a result of the following: the Rover pipeline being placed fully in-service in November 2018;~~crude production ~~increases in the Haynesville Shale and deliveries to intrastate markets~~ resulting in ~~increased deliveries off of our Tiger pipeline;~~lower associated gas and ~~increased utilization of higher contracted capacity on the Panhandle and Trunkline pipelines.~~a decrease in demand for LNG export.

Segment Adjusted EBITDA. For the three months ended ~~September~~June 30, ~~2019~~2020 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:

an increase of $37 million in operating expenses primarily due to an increase to ad valorem expenses of $48 million on the Rover pipeline system due to placing the final portions of this asset into service, partially offset by $5 million in lower maintenance expenditures and $4 million in lower storage lease expenses on our Panhandle system due to lower leased capacity; and

a decrease in EBITDA from unconsolidated affiliates of $11 million primarily resulting from a $7 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted and lower rates on expiring contracts, and a $3 million decrease due to Citrus resulting from the Texas Brine settlement being received in 2018; partially offset by

•

~~an increase~~a decrease of ~~$24~~$43 million in reservation fees ~~from placing the Rover pipeline fully in-service and $7~~primarily due to a decrease of $18 million from additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease of $16 million from lower rates on Lake Charles LNG effective January 2020 and a decrease of $12 million due to less capacity sold on our Panhandle and Trunkline systems as well as lower rates on the sale of uncommitted capacity on our Rover pipeline. These decreases were partially offset by increased ~~utilization of~~margin from our Transwestern ~~and Trunkline pipelines; and~~ system due to increased demand in firm transportation;

~~an increase of $4 million in interruptible transportation volumes due to improved market conditions on our Rover, Transwestern, Trunkline and Panhandle pipeline systems.~~


•	a decrease of $4 million in interruptible transportation due to lower rates and lower short-term customer demand on our Sea Robin and Transwestern systems; and

•

a decrease of $10 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower earnings of $12 million from our Midcontinent Express Pipeline joint venture as a result of less capacity sold and lower rates received following the expiration of certain contracts, partially offset by a $2 million increase from Citrus primarily due to higher margins and lower operating expenses.

Segment Adjusted EBITDA. For the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment ~~increased~~decreased due to the net impacts of the following:

~~an increase of $228 million from placing the Rover pipeline in-service;~~


•	an increase of $39 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Rover, Transwestern, Tiger and Panhandle systems;


•	~~an increase of $8 million on our Panhandle pipeline system primarily from additional gas processing revenues;~~


•	~~an increase of $4 million from increased rates and additional volume delivered from the Sea Robin pipeline as a result of fewer third-party supply interruptions compared to the prior period; and~~


•	~~a decrease of $6 million in selling, general and administrative expenses primarily due to lower excise tax on our Rover system; partially offset by~~


•	~~an increase of~~ ~~$113 million~~ ~~in operating expense primarily due to a reverse to ad valorem taxes on the Rover pipeline system due to placing the final portions of this asset into service; and~~

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•

a decrease of $6$73 million in ~~Adjusted EBITDA from unconsolidated affiliates~~reservation fees primarily due to a ~~$10~~decrease of $18 million from additional revenue recognized in 2019 associated with a shipper bankruptcy, a decrease ~~in earnings from MEP as a result~~ of ~~lower~~$30 million due to less capacity ~~being re-contracted and~~sold at lower rates on ~~expiring contracts,~~our Panhandle and Trunkline system as well as lower rates on the sale of uncommitted capacity on our Rover pipeline, and a decrease of $32 million due to a contractual rate adjustment on commitments at our Lake Charles LNG facility. These decreases were partially offset by ~~a $3 million increase~~increased revenues from ~~new fixed transportation contracts on Citrus.~~our Transwestern system due to increased demand in firm transportation;

a decrease of $8 million in operational gas sales, interruptible transportation, parking and storage revenue due to unfavorable market conditions;

an increase of $5 million in selling, general and administrative expenses primarily due to higher allocated overhead costs and an increase in reserves for insurance claims; and

a decrease of $23 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower earnings from our Midcontinent Express Pipeline joint venture as a result of less capacity sold and lower rates received following the expiration of certain contracts; partially offset by

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a decrease of $2 million in operating expenses primarily due to lower employee costs resulting from cost-cutting initiatives of $10 million and an $8 million decrease in ad valorem taxes, partially offset by bad debt expense of $10 million and a $5 million change in lower of cost or market adjustments.

Midstream


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
Gathered volumes (BBtu/d)	13,955			12,774			1,181			13,278			11,890			1,388			12,964			13,148			(184		)	13,155			12,934			221
NGLs produced (MBbls/d)	574			583			(9		)	567			533			34			602			565			37			606			564			42
Equity NGLs (MBbls/d)	30			32			(2		)	32			31			1			37			30			7			37			33			4
Revenues	$	1,580		$	2,253		$	(673	)	$	4,496		$	5,741		$	(1,245	)	$	1,018		$	1,198		$	(180	)	$	2,188		$	2,916		$	(728	)
Cost of products sold	953			1,631			(678		)	2,678			3,973			(1,295		)	473			584			(111		)	1,048			1,725			(677		)
Segment margin	627			622			5			1,818			1,768			50			545			614			(69		)	1,140			1,191			(51		)
Operating expenses, excluding non-cash compensation expense	(202		)	(179		)	(23		)	(574		)	(512		)	(62		)	(166		)	(189		)	23			(359		)	(372		)	13
Selling, general and administrative expenses, excluding non-cash compensation expense	(21		)	(19		)	(2		)	(63		)	(59		)	(4		)	(20		)	(23		)	3			(46		)	(42		)	(4		)
Adjusted EBITDA related to unconsolidated affiliates	6			9			(3		)	21			25			(4		)	7			9			(2		)	14			15			(1		)
Other	1			1			—			3			3			—			1			1			—			1			2			(1		)
Segment Adjusted EBITDA	$	411		$	434		$	(23	)	$	1,205		$	1,225		$	(20	)	$	367		$	412		$	(45	)	$	750		$	794		$	(44	)

Volumes. ~~For~~Gathered volumes decreased during the three months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year ~~gathered volumes increased~~ primarily due to ~~new production~~decreases in the ~~Northeast,~~ South Texas and North Texas regions, partially offset by the impact of the SemGroup acquisition in the Mid-Continent/Panhandle 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. ~~For~~

Gathered volumes increased during the ~~three~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year ~~NGL production decreased~~primarily due to ~~ethane rejection~~the impact of the SemGroup acquisition in the Mid-Continent/Panhandle region and volume increases in the Northeast region, partially offset by decreases in the South Texas ~~and North Texas regions. For the nine months ended September 30, 2019 compared to the same period last year, gathered volumes and~~region. NGL production increased due to the impact of the SemGroup acquisition in the ~~Northeast,~~Mid-Continent/Panhandle region and increased ethane recovery in the Permian, South Texas and North Texas ~~South Texas, Permian and Ark-La-Tex~~ regions.

Segment Margin. The table below presents the components of our midstream segment margin. For the prior ~~periods~~period included in the table below, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect ~~the~~ reclassification of certain contractual minimum fees in order to conform to the current period ~~classification. For the three and nine months ended September 30, 2018, a total of $2 million and $11 million, respectively, was reclassified from fee-based margin to non-fee-based margin.~~classification:


	Three Months Ended September 30,							Nine Months Ended September 30,							Three Months Ended June 30,							Six Months Ended June 30,
	2019		2018		Change			2019		2018		Change			2020		2019		Change			2020		2019		Change
Gathering and processing fee-based revenues	$	517	$	458	$	59		$	1,488	$	1,319	$	169		$	503	$	530	$	(27	)	$	1,033	$	1,034	$	(1	)
Non-fee-based contracts and processing	110		164		(54		)	330		449		(119		)	42		84		(42		)	107		157		(50		)
Unrealized gains (losses) on commodity risk management activities	—		—		—			—		—		—
Total segment margin	$	627	$	622	$	5		$	1,818	$	1,768	$	50		$	545	$	614	$	(69	)	$	1,140	$	1,191	$	(51	)

Segment Adjusted EBITDA. For the three months ended ~~September~~June 30, ~~2019 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:~~

a decrease of $54 million in non-fee-based margin due to lower NGL prices of $51 million and lower gas prices of $14 million, partially offset by an increase of $11 million from increased throughput volumes in the Permian region;

~~an increase of $2 million in selling, general and administrative expenses due to an increase in allocated overhead costs; and~~

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•	~~an increase of $23 million in operating expenses primarily due to increases in outside services, maintenance project costs, and employee costs; partially offset by~~

~~an increase of $59 million in fee-based margin due to volume growth in the Northeast, Permian and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions.~~

~~Segment Adjusted EBITDA.~~ ~~For the nine months ended September 30, 2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:


•	a decrease ~~of $119~~$39 million in non fee-based margin due ~~primarily~~ to lower NGL ~~prices~~prices;


•	a decrease of ~~$123~~$3 million ~~and lower gas prices of $37 million, partially offset by an increase of $41 million~~in non-fee based margin due to ~~increased~~decreased throughput volume in the ~~North~~South Texas region; and


•	a decrease of $27 million in fee-based margin due to volume declines in the South Texas and ~~Permian~~North Texas regions; partially offset by

~~an increase~~

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a decrease of $23 million in operating expenses ~~primarily~~ due to ~~increases~~decreases of ~~$27~~$11 million in outside services, ~~$12 million in maintenance project costs, and $12~~$8 million in employee ~~costs;~~costs and $3 million in materials; and


•	a decrease of $3 million in selling, general and administrative expenses due to a decrease in allocated overhead costs.

Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:

a decrease of $61 million in non-fee-based margin due to lower NGL prices of $56 million and lower gas prices of $5 million;


•	an increase of $4 million in selling, general and administrative expenses ~~primarily~~ due to an ~~insurance payment received~~increase of $3 million in ~~the prior period;~~capitalized overhead costs and an increase of $1 million in insurance; partially offset by


•	an increase of ~~$169~~$11 million in ~~fee-based~~non-fee-based margin due to increased throughput volume ~~growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions, offset by declines~~ in the Mid-Continent/Panhandle ~~regions.~~region as a result of the SemGroup acquisition; and


•	a decrease of $13 million in operating expenses due to decreases of $11 million in outside services, $4 million in employee costs and $3 million in materials, partially offset by an increase of $7 million in maintenance project costs.

NGL and Refined Products Transportation and Services


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
NGL transportation volumes (MBbls/d)	1,346			1,086			260			1,277			997			280			1,401			1,305			96			1,400			1,237			163
Refined products transportation volumes (MBbls/d)	552			627			(75		)	599			628			(29		)	377			628			(251		)	460			623			(163		)
NGL and refined products terminal volumes (MBbls/d)	963			858			105			948			784			164			748			885			(137		)	798			831			(33		)
NGL fractionation volumes (MBbls/d)	713			567			146			697			505			192			836			701			135			820			690			130
Revenues	$	2,878		$	3,063		$	(185	)	$	8,521		$	8,177		$	344		$	2,119		$	2,612		$	(493	)	$	4,834		$	5,643		$	(809	)
Cost of products sold	1,962			2,429			(467		)	6,136			6,356			(220		)	1,368			1,848			(480		)	3,204			4,174			(970		)
Segment margin	916			634			282			2,385			1,821			564			751			764			(13		)	1,630			1,469			161
Unrealized losses on commodity risk management activities	(81		)	26			(107		)	15			26			(11		)	78			39			39			23			96			(73		)
Operating expenses, excluding non-cash compensation expense	(167		)	(168		)	1			(471		)	(448		)	(23		)	(154		)	(155		)	1			(313		)	(304		)	(9		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(22		)	(17		)	(5		)	(67		)	(52		)	(15		)	(19		)	(26		)	7			(44		)	(45		)	1
Adjusted EBITDA related to unconsolidated affiliates	24			23			1			63			63			—			18			21			(3		)	41			39			2
Other	(3		)	—			(3		)	(2		)	—			(2		)	—			1			(1		)	—			1			(1		)
Segment Adjusted EBITDA	$	667		$	498		$	169		$	1,923		$	1,410		$	513		$	674		$	644		$	30		$	1,337		$	1,256		$	81

Volumes. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same periods last year, NGL transportation volumes increased due to higher throughput volumes on our Mariner East pipeline system. In addition, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. ~~In addition, NGL transportation volumes on our Northeast assets increased due to the initiation of service on the Mariner East 2 pipeline system.~~

Refined products transportation volumes decreased for the three and ~~nine~~six months ended ~~September~~June 30, 2020 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 demand for jet fuel and other refined products. These decreases in volumes are partially offset by the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019.

NGL and refined products terminal volumes decreased for the three and six months ended June 30, 2020 compared to the same periods last year primarily due to the closure of ~~the Philadelphia Energy Services~~a third-party refinery during the third quarter of ~~2019.~~

~~NGL~~2019, and less domestic demand for jet fuel and other refined ~~products terminal~~products. These decreases were partially offset by higher volumes ~~increased for the three and nine months ended September 30, 2019 compared to the same periods last year primarily due to the initiation of service on~~from our Mariner East ~~2 pipeline which commenced operations in the fourth quarter of 2018.~~ system,

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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.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased 20% for both the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same periods last year primarily due to the commissioning of our ~~fifth~~sixth and ~~sixth~~seventh fractionators in ~~July 2018~~February 2019 and February ~~2019,~~2020, respectively.

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 June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
Transportation margin	$	474		$	322		$	152		$	1,259		$	878		$	381		$	449		$	422		$	27		$	925		$	785		$	140
Fractionators and refinery services margin	171			141			30			491			365			126			173			154			19			352			320			32
Terminal services margin	175			130			45			478			353			125			129			166			(37		)	280			303			(23		)
Storage margin	57			50			7			166			154			12			55			53			2			118			109			9
Marketing margin	(42		)	17			(59		)	6			97			(91		)	23			8			15			(22		)	48			(70		)
Unrealized losses on commodity risk management activities	81			(26		)	107			(15		)	(26		)	11			(78		)	(39		)	(39		)	(23		)	(96		)	73
Total segment margin	$	916		$	634		$	282		$	2,385		$	1,821		$	564		$	751		$	764		$	(13	)	$	1,630		$	1,469		$	161

Segment Adjusted EBITDA. For the three months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

an increase of $152 million in transportation margin primarily due to an $87 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $54 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, and an $11 million increase due to higher throughput volumes received from the Barnett and Southeast Texas regions;

•

an increase of ~~$45~~$27 million in ~~terminal services~~transportation margin primarily due to a $28 million increase from higher throughput volumes on our Mariner East pipeline system, an $11 million increase from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $6 million increase due to the initiation of service on our ~~Mariner East 2~~JC Nolan diesel fuel pipeline in the ~~fourth~~third quarter of ~~2018;~~ 2019, and a $4 million increase due to higher throughput volumes from the Southeast Texas region. These increases were partially offset by an $8 million decrease due to a reclassification between our transportation and fractionators margins, a $7 million decrease due to less domestic demand for jet fuel and other refined products, a $5 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019, and a $2 million decrease due to lower third-party volumes on our Mariner West pipeline;

an increase of $30 million in fractionation and refinery services margin primarily resulting from the commissioning of our sixth fractionator in February 2019 and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $3 million decrease resulting from a reclassification between our fractionation and storage margins; and

an increase of $7 million in storage margin primarily due to a $3 million increase from throughput pipeline fees collected at our Mont Belvieu storage facility, a $3 million increase resulting from a reclassification between our storage and fractionation margins; partially offset by

a decrease of $59 million in marketing margin primarily due to lower optimization gains resulting from less favorable market conditions and an $8 million write down on the value of stored NGL inventory; and

•

an increase of $5$15 million in ~~selling, general and administrative expenses~~marketing margin primarily due to a $3$50 million increase ~~in allocated overhead costs~~due to higher optimization gains from the sale of NGL component products at our Mont Belvieu facility and a $2$10 million increase due to write-downs of NGL inventory in ~~legal fees.~~the second quarter of 2019. These increases were partially offset by lower gains from our butane blending business during the second quarter of 2020 due to unfavorable market conditions; and

•

an increase of $19 million in fractionators and refinery services margin primarily due to a $15 million increase resulting from the commissioning of our seventh fractionator in February 2020 and higher NGL volumes from the Permian and Barnett regions feeding our Mont Belvieu fractionation facility, and an increase of $8 million due to a reclassification between our transportation and fractionators margins. These increases were partially offset by a $4 million decrease due to the expiration of a third-party blending contract during the second quarter of 2020; partially offset by

•

a decrease of $37 million in terminal services margin primarily due to a $25 million decrease resulting from the expiration of a third party contract at our Nederland export facility in the second quarter of 2020, a $9 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Industrial Complex, a $6 million decrease due to less domestic demand for jet fuel and other refined products, and a $4 million decrease due to the closure of a third-party refinery. These decreases were partially offset by a $6 million increase due to higher throughput on our Mariner East system.

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Segment Adjusted EBITDA. For the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

an increase of $381 million in transportation margin primarily due to a $180 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $177 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, and a $21 million increase due to higher throughput volumes from the Barnett and Southeast Texas regions;

•

an increase of ~~$126~~$140 million in ~~fractionation and refinery services~~transportation margin primarily due to a ~~$142~~$103 million increase from higher throughput volumes on our Mariner East pipeline system, a $46 million increase resulting from ~~the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and~~ higher ~~NGL~~throughput volumes received from the Permian region ~~feeding~~on our ~~Mont Belvieu fractionation facility. This~~Texas NGL pipelines, a $14 million increase ~~was~~due to the initiation of service on our JC Nolan diesel fuel pipeline in the third quarter of 2019, a $9 million increase due to higher throughput volumes from the Barnett region, and a $6 million increase due to higher throughput from the Southeast Texas region. These increases were partially offset by an $11 million decrease resulting from the closure of a third-party refinery during the third quarter of 2019, a $10 million decrease ~~resulting from~~due to less domestic demand for jet fuel and other refined products, an $8 million decrease due to a reclassification between our ~~fractionation~~transportation and ~~storage~~fractionators margins, ~~and an $8~~a $5 million decrease ~~in refinery services margin primarily~~ due to lower ~~pricing spreads;~~volumes from the Eagle Ford region, and a $3 million decrease due to lower third-party volumes on our Mariner West pipeline;

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•

an increase of ~~$125~~$32 million in ~~terminal~~fractionators and refinery services margin primarily due to a ~~$130~~$25 million increase resulting from the commissioning 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, an $8 million increase due to ~~the initiation of service on~~a reclassification between our ~~Mariner East 2 pipeline in the fourth quarter of 2018~~transportation and fractionators margins, and a ~~$10~~$3 million increase ~~due to higher throughput at~~in truck and rail volumes feeding our ~~refined product terminals in the Northeast.~~refinery services facility. These increases were partially offset by a ~~$16~~$6 million decrease due to ~~lower volumes from third party pipeline, truck and rail delivered into our Marcus Hook terminal;~~the expiration of a third-party blending contract during the second quarter of 2020; and

~~an increase of $12 million in storage margin primarily due to a $10 million increase resulting from a reclassification between our storage and fractionation margins; partially offset by~~

a decrease of $91 million in marketing margin primarily due to lower optimization gains resulting from less favorable market conditions and an $8 million write down on the value of stored NGL inventory;

an increase of $23 million in operating expenses primarily due to an $18 million increase in employee and ad valorem expenses on our terminals and fractionation assets and a $15 million increase in utility costs to operate our pipelines and fifth and sixth fractionators, which commenced service in July 2018 and February 2019, respectively. These increases were partially offset by an $11 million decrease in outside services on our transportation and terminal assets; and

•

an increase of ~~$15~~$9 million ~~iin selling, general and administrative expenses~~in storage margin primarily due to a $6 million increase in ~~allocated overhead costs,~~fees generated from exported volumes and a $4$3 million increase ~~in legal fees, a $2 million increase in insurance expenses, a $2 million increase in employee costs, and a $2 million increase in management fees.~~from higher throughput; partially offset by

•

a decrease of $70 million in marketing margin primarily due to a $54 million decrease due to lower gains from our butane and gasoline blending business due to unfavorable market conditions, a $35 million decrease from capacity lease fees incurred by our marketing affiliate on our Mariner East pipeline system and a $12 million decrease due to fewer export and rack sales. These decreases were partially offset by higher optimization gains from the sale of NGL component products at our Mont Belvieu facility;

•

a decrease of $23 million in terminal services margin primarily due to a $25 million decrease resulting from the expiration of a third-party contract at our Nederland export facility in the second quarter of 2020, a $16 million decrease due to lower third-party and intercompany volumes feeding our Marcus Hook Industrial Complex, a $10 million decrease due to a closure of a third-party refinery, and an $8 million decrease due to less domestic demand for jet fuel and other refined products. These decreases were partially offset by a $33 million increase due to higher throughput on our Mariner East system and a $3 million increase resulting from initiation of service of our natural gasoline export in the third quarter of 2019; and

an increase of $9 million in operating expenses primarily due to increases totaling $15 million for costs associated with operating additional assets as well as an increase in throughput volumes, partially offset by a $5 million reduction to lower power costs.

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Crude Oil Transportation and Services


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
Crude transportation volumes (MBbls/d)	4,661			4,276			385			4,638			4,119			519			3,590			4,266			(676		)	4,021			4,158			(137		)
Crude terminals volumes (MBbls/d)	1,905			2,134			(229		)	2,125			2,060			65			2,716			2,846			(130		)	2,851			2,704			147
Revenues	$	4,453		$	4,438		$	15		$	13,685		$	12,986		$	699		$	1,839		$	5,046		$	(3,207	)	$	6,052		$	9,232		$	(3,180	)
Cost of products sold	3,620			3,494			126			10,857			11,032			(175		)	1,175			4,136			(2,961		)	4,633			7,298			(2,665		)
Segment margin	833			944			(111		)	2,828			1,954			874			664			910			(246		)	1,419			1,934			(515		)
Unrealized (gains) losses on commodity risk management activities	(2		)	(118		)	116			(100		)	187			(287		)	—			11			(11		)	10			(98		)	108
Operating expenses, excluding non-cash compensation expense	(110		)	(126		)	16			(410		)	(397		)	(13		)	(131		)	(150		)	19			(289		)	(300		)	11
Selling, general and administrative expenses, excluding non-cash compensation expense	(21		)	(22		)	1			(61		)	(64		)	3			(26		)	(20		)	(6		)	(54		)	(40		)	(14		)
Adjusted EBITDA related to unconsolidated affiliates	1			4			(3		)	—			14			(14		)	11			1			10			23			(1		)	24
Other	(1		)	—			(1		)	—			—			—			1			—			1			1			1			—
Segment Adjusted EBITDA	$	700		$	682		$	18		$	2,257		$	1,694		$	563		$	519		$	752		$	(233	)	$	1,110		$	1,496		$	(386	)

Volumes. For the three ~~and nine~~ months ended ~~September~~June 30, ~~2019~~2020 compared to the same ~~periods~~period last year, crude transportation and terminal volumes ~~benefited from an increase in barrels through~~were lower due to decreased demand on our ~~existing~~ Texas ~~pipelines~~pipeline system and our Bakken ~~pipeline. Crude terminal~~pipeline, driven by lower production in these regions as well as lower refinery utilization, partly offset by contributions from assets acquired in 2019.

For the six months ended June 30, 2020 compared to the same period last year, crude transportation volumes were lower due to decreased ~~for the three month period as a result of the closure of a~~demand on our Texas pipeline system and our Bakken pipeline, driven by lower production in these regions and lower refinery ~~that was the primary customer utilizing one of our northeast crude terminals.~~utilization. Terminal volumes were higher due to contributions from assets acquired in 2019.

Segment Adjusted EBITDA. For the three months ended ~~September~~June 30, ~~2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services ~~segment increased due to the net impacts of the following:~~

an increase of $5 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $63 million increase from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region, a $50 million increase from higher throughput on the Bakken pipeline, and a $6 million increase from higher ship loading and tank rental fees at our Nederland terminal; partially offset by a $106 million decrease (excluding a net change of $116 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from non-cash inventory valuation adjustments and lower basis differentials between the Permian producing region and the Nederland terminal on the Gulf Coast, as well as a $5 million decrease due to lower throughput volumes at our refinery terminal in the Northeast. The remainder of the offsetting decrease

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was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period;

~~a decrease of $16 million in operating expenses primarily due to the impact of certain intrasegment transactions discussed above, partially offset by a $17 million increase in ad valorem taxes; and~~


•	~~a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.~~

~~Segment Adjusted EBITDA.~~ For the nine months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

•

an increase of $587 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $355 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers, a $216 million favorable variance resulting from increased throughput on the Bakken pipeline, a $26 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland terminal, and an $8 million increase (excluding a net change of $287 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from improved basis differentials between the Permian and Bakken producing regions to our Nederland terminal on the Texas Gulf Coast, partially offset by a $6 million decrease due to lower throughput volumes at our refinery terminal in the Northeast. The remainder of the offsetting decrease was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period; and


•	~~an increase of $13 million in operating expenses primarily due to a $34 million increase in throughput related costs on existing assets, and a~~ ~~$7 million increase in ad valorem taxes, partially offset by a $10 million decrease in management fees, as well as the impact of certain intrasegment transactions discussed above; and~~

~~a decrease of $14 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.~~

~~Investment in Sunoco LP~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2019 2018 Change 2019 2018 Change
Revenues $ 4,331
$ 4,761
$ (430 ) $ 12,498
$ 13,117
$ (619 )
Cost of products sold 4,039
4,428
(389 ) 11,567
12,178
(611 )
Segment margin 292
333
(41 ) 931
939
(8 )
Unrealized gains on commodity risk management activities (1 ) —
(1 ) (4 ) —
(4 )
Operating expenses, excluding non-cash compensation expense (94 ) (106 ) 12
(281 ) (324 ) 43
Selling, general and administrative expenses, excluding non-cash compensation expense (36 ) (30 ) (6 ) (91 ) (93 ) 2
Adjusted EBITDA related to unconsolidated affiliates 1
—
1
1
—
1
Inventory valuation adjustments 26
7
19
(71 ) (50 ) (21 )
Adjusted EBITDA related to discontinued operations —
—
—
—
(25 ) 25
Other 4
4
—
12
10
2
Segment Adjusted EBITDA $ 192
$ 208
$ (16 ) $ 497
$ 457
$ 40

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

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~~Segment Adjusted EBITDA.~~ ~~For the three months ended September 30, 2019 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 of ~~$23~~$257 million in segment margin ~~excluding inventory valuation adjustments and~~(excluding unrealized gains and losses on commodity risk management ~~activities,~~ activities) primarily due to a ~~one-time benefit~~$62 million decrease (excluding a net change of ~~approximately $25~~$11 million ~~related~~in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business due to well shut-ins resulting in unfulfilled producer supply commitments, as well as unfavorable pricing conditions impacting our Permian to Gulf Coast and Bakken to Gulf Coast trading operations, a ~~cash settlement with~~$123 million decrease from our Texas crude pipeline system due to lower utilization due in part to well shut-ins, as well as lower average tariff rates realized, a ~~fuel supplier~~$117 million decrease due to lower volumes on our Bakken Pipeline resulting from well shut-ins, a $10 million decrease in ~~the prior period,~~marine throughput at our crude terminals, and a $7 million decrease due to lower volumes on our Bayou Bridge Pipeline, partially offset by an increase of $74 million related to assets acquired in ~~motor fuel gallons sold;~~2019; and

an increase of $6 million in selling, general and administrative expenses primarily due to a $3 million increase in legal expenses, and a $2 million increase in insurance expenses, partially offset by a $1 million decrease in allocated overhead costs; offset by


•	a decrease of $19 million in operating expenses primarily due to lower volume-driven pipeline expenses, partially offset by increased costs related to assets acquired in 2019; and


•	an increase of $10 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019.

Segment Adjusted EBITDA. For the six months ended June 30, 2020 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 $407 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $268 million decrease (excluding a net change of $108 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business due primarily to unfavorable pricing conditions, as well as unfulfilled producer supply commitments due to well shut-ins, impacting our Permian to Gulf Coast

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and Bakken to Gulf Coast trading operations, a $194 million decrease from our Texas crude pipeline system due to lower utilization due in part to well shut-ins, as well as lower average tariff rates realized, a $97 million decrease due to lower volumes on our Bakken Pipeline resulting from well shut-ins, and an $8 million decrease in marine throughput at our crude terminals, offset by a $162 million increase related to assets acquired in 2019 and an $11 million increase due to higher volumes on our Bayou Bridge Pipeline; and


•	an increase of $14 million in selling, general and administrative expenses primarily due to a $4 million increase in legal expenses, a $4 million increase related to assets acquired in 2019, a $2 million increase in insurance expenses, and a $2 million increase in allocated overhead costs; partially offset by


•	a ~~net~~ decrease of $6$11 million in operating expenses ~~and selling, general and administrative~~primarily due to lower volume-driven pipeline expenses, ~~excluding non-cash compensation, primarily as a result of lower lease expense~~partially offset by increased costs related to assets acquired in 2019; and ~~utilities.~~


•	an increase of $24 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired in 2019.

Investment in Sunoco LP



	Three Months Ended June 30,									Six Months Ended June 30,
	2020			2019			Change			2020			2019			Change
Revenues	$	2,080		$	4,475		$	(2,395	)	$	5,352		$	8,167		$	(2,815	)
Cost of products sold	1,722			4,206			(2,484		)	4,886			7,528			(2,642		)
Segment margin	358			269			89			466			639			(173		)
Unrealized (gains) losses on commodity risk management activities	—			3			(3		)	6			(3		)	9
Operating expenses, excluding non-cash compensation expense	(72		)	(89		)	17			(181		)	(187		)	6
Selling, general and administrative expenses, excluding non-cash compensation expense	(22		)	(31		)	9			(52		)	(55		)	3
Adjusted EBITDA related to unconsolidated affiliates	3			—			3			5			—			5
Inventory valuation adjustments	(90		)	(4		)	(86		)	137			(97		)	234
Other	5			4			1			10			8			2
Segment Adjusted EBITDA	$	182		$	152		$	30		$	391		$	305		$	86

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

Segment Adjusted EBITDA. For the ~~nine~~three months ended ~~September~~June 30, ~~2019~~2020 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 ~~aggregate~~increase of $16 million in motor fuel sales as a result of an increase in gross profit per gallon sold, partially offset by a decrease in gallons sold;

a decrease of $26 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; and

an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates which was attributable to the JC Nolan joint venture entered into in 2019; partially offset by

a decrease of $15 million in non-motor fuel sales gross margin as a result of reduced credit card transactions related to the COVID-19 pandemic.

Segment Adjusted EBITDA. For the six months ended June 30, 2020 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 of $84 million in motor fuel sales as a result of a 39.6% 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 14.6% decrease in gallons sold;

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•

a decrease of ~~$45~~$9 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation expense, primarily ~~due~~attributable to lower employee costs, maintenance, advertising, credit card fees and utilities. This decrease is primarily offset by a $16 million charge for current credit losses on Sunoco LP’s accounts receivable in connection with the ~~conversion of 207 retail sites to commission agent sites in April 2018;~~financial impact from COVID-19; and


•	an increase ~~of $25 million~~ in unconsolidated affiliate Adjusted EBITDA ~~from discontinued operations due~~of $5 million, which was attributable to ~~Sunoco LP’s retail divestment~~the JC Nolan joint venture entered into in ~~January 2018;~~2019; partially offset by

•

a decrease of ~~$33~~$13 million in ~~segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities,~~non motor fuel sales primarily due to ~~a one-time benefit of approximately $25 million~~reduced credit card transactions related to ~~a cash settlement with a fuel supplier in~~ the ~~prior period and an $8 million one-time charge related to a reserve for an open contractual dispute in the current period, partially offset by an increase in motor fuel gallons sold.~~COVID-19 pandemic.

Investment in USAC


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
Revenues	$	175		$	169		$	6		$	520		$	336		$	184		$	169		$	174		$	(5	)	$	348		$	345		$	3
Cost of products sold	23			24			(1		)	69			44			25			18			24			(6		)	42			46			(4		)
Segment margin	152			145			7			451			292			159			151			150			1			306			299			7
Operating expenses, excluding non-cash compensation expense	(35		)	(42		)	7			(102		)	(80		)	(22		)	(30		)	(32		)	2			(65		)	(67		)	2
Selling, general and administrative expenses, excluding non-cash compensation expense	(13		)	(15		)	2			(39		)	(34		)	(5		)	(16		)	(13		)	(3		)	(30		)	(26		)	(4		)
Other	—			2			(2		)	—			7			(7		)
Segment Adjusted EBITDA	$	104		$	90		$	14		$	310		$	185		$	125		$	105		$	105		$	—		$	211		$	206		$	5

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

Segment Adjusted EBITDA. For the three months ended ~~September~~June 30, ~~2019~~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:


•	an increase of $3 million in selling, general and administrative expenses primarily due to an increase in the provision for expected credit losses; offset by


•	a decrease of $2 million in operating expenses, as well as an increase of $1 million in segment margin primarily due to a decrease in cost of products sold offset by a decrease in revenues as a result of a decrease in average revenue generating horsepower.

Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:


•	an increase of $7 million in segment margin primarily due to an increase revenues as a result of an increase in ~~demand for compression services driven~~fleet horsepower and a decrease in cost of products sold; partially offset by ~~increased U.S. production of crude oil and natural gas;~~

•

~~a decrease~~an increase of $7 million in operating expenses primarily due to a $3 million decrease in outside maintenance services, a $2 million decrease in ad valorem taxes primarily due to prior year refunds received in the current period, a $2 million decrease in direct labor costs, and a $1 million decrease in indirect expenses, such as transportation and freight, partially offset by a $3 million increase in parts and fluids expenses as a result of higher revenue generating horsepower; and


•	~~a decrease of $2~~$4 million in selling, general and administrative expenses primarily due to ~~transaction related expenses as a result of transactions completed during 2018.~~ an increase in the provision for expected credit losses.

Amounts reflected above for the nine months ended September 30, 2019 reflects the consolidated results of USAC. Changes between periods are primarily due to the consolidation of USAC beginning April 2, 2018, the date ET obtained control of USAC.

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All Other


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			Change			2019			2018			Change			2020			2019			Change			2020			2019			Change
Revenues	$	441		$	525		$	(84	)	$	1,276		$	1,599		$	(323	)	$	492		$	391		$	101		$	1,005		$	888		$	117
Cost of products sold	393			500			(107		)	1,138			1,421			(283		)	377			343			34			792			798			(6		)
Segment margin	48			25			23			138			178			(40		)	115			48			67			213			90			123
Unrealized (gains) losses on commodity risk management activities	1			7			(6		)	(4		)	9			(13		)	2			(4		)	6			(3		)	(5		)	2
Operating expenses, excluding non-cash compensation expense	(39		)	(9		)	(30		)	(52		)	(50		)	(2		)	(27		)	(6		)	(21		)	(65		)	(13		)	(52		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(9		)	(26		)	17			(42		)	(63		)	21			(19		)	(20		)	1			(51		)	(33		)	(18		)
Adjusted EBITDA related to unconsolidated affiliates	—			2			(2		)	1			1			—			—			2			(2		)	—			1			(1		)
Other and eliminations	36			(5		)	41			42			(6		)	48			(67		)	(7		)	(60		)	(48		)	6			(54		)
Segment Adjusted EBITDA	$	37		$	(6	)	$	43		$	83		$	69		$	14		$	4		$	13		$	(9	)	$	46		$	46		$	—

Amounts reflected in our all other segment primarily include:

our natural gas marketing operations;

our wholly-owned natural gas compression operations;

a noncontrolling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent to the August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate; and

our investment in coal handling ~~facilities.~~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~~June 30, ~~2019 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased due to the net impacts of the following:~~


•	~~an increase of $3 million from power trading activities;~~


•	~~an increase of $5 million in optimized gains on residue gas sales;~~


•	~~an increase of $5 million from settled derivatives;~~


•	~~an increase of $6 million from the recognition of deferred revenue related to a bankruptcy; and~~


•	a decrease of $17 million in selling, general and administrative expenses, which includes a decrease of $9 million in merger and acquisition expenses, a decrease of $6 million in professional fees, and a decrease of $4 million in insurance expenses.

~~Segment Adjusted EBITDA.~~ ~~For the nine months ended September 30, 2019~~2020 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:


•	~~an increase~~a decrease of ~~$13~~$7 million ~~in gains from park and loan and storage activity;~~due to lower sales of residue gas;


•	~~an increase~~a decrease of $9$11 million ~~in optimized gains on residue gas sales;~~due to lower revenues from our compression equipment business;

a decrease of $7 million due to power trading activities;

a decrease of $5 million due to lower demand and operator production at our natural resources business;


•	~~an increase~~a decrease of $6$4 million ~~from the recognition of deferred revenue related~~due to ~~a bankruptcy;~~storage gains; and


•	a decrease of ~~$21~~$3 million ~~in selling, general and administrative expenses primarily due to lower merger and acquisition and other expenses;~~ from increased power costs at our compression services business; partially offset by


•	an increase of $25 million from the acquisition of SemCAMS; and


•	an increase of $6 million in settled derivatives.

Segment Adjusted EBITDA. For the six months ended June 30, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment was comparable due to the net impacts of the following:


•	a decrease of ~~$36~~$9 million from power trading activities;


•	a decrease of $9 million due to ~~the contribution~~lower sales of ~~CDM~~residue gas;


•	a decrease of $6 million due to ~~USAC in April 2018, subsequent~~lower gas prices and increased power costs at our compression services business;


•	a decrease of $4 million due to ~~which CDM is reflected in the Investment in USAC Segment;~~storage, park and loan operations;


•	a decrease of $18 million due to lower revenue from our compression equipment business;


•	a decrease of $20 million due to higher merger and acquisition expense;


•	a decrease of $8 million due to lower demand and operator production at our natural resources business; and

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•	a decrease of $5 million due to ~~lower revenue~~the elimination of Sunoco LP’s interest in our JC Nolan joint venture; partially offset by


•	an increase of $51 million from the acquisition of SemCAMS;


•	an increase of $17 million from settlement payments received from our ~~compressor equipment business.~~ownership of PES; and


•	an increase of $8 million in settled derivatives.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Our ability to satisfy ~~its~~ obligations and pay distributions to ~~its~~ unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

We currently expect capital expenditures in ~~2019~~2020 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	$	75	$	100	$	35	$	40	$	10	$	20	$	40	$	45
Interstate transportation and storage ⁽¹⁾	250		275		145		150		75		100		115		120
Midstream	675		700		145		150		450		475		105		110
NGL and refined products transportation and services	2,475		2,500		90		100		2,425		2,525		95		105
Crude oil transportation and services ⁽¹⁾	300		325		100		110		275		300		130		140
All other (including eliminations)	150		175		50		55		75		100		55		60
Total capital expenditures	$	3,925	$	4,075	$	565	$	605	$	3,310	$	3,520	$	540	$	580


⁽¹⁾	Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

~~For 2020, ETO expects growth capital expenditures to be approximately $4 billion, excluding Sunoco LP, USAC and expenditures related to the SemGroup transaction.~~

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, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control; however, we have included these factors in our anticipated growth capital expenditures for each year.

We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally fund growth capital expenditures with borrowings under credit facilities, long-term debt, the issuance of additional preferred units or a combination thereof.

Sunoco LP

~~Excluding acquisitions,~~ Sunoco LP currently expects to spend approximately ~~$115~~$30 million on growth capital and ~~$40~~$75 million on maintenance capital for the full year ~~2019.~~2020.

USAC

USAC currently plans to spend approximately ~~$28~~$30 million inon maintenance capital expenditures during ~~2019,~~2020, including parts consumed from inventory.

Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between ~~$145~~$80 million and ~~$155~~$90 million in expansion capital expenditures during ~~2019.~~2020. As of ~~September~~June 30, ~~2019,~~2020, USAC has binding commitments to purchase ~~$48~~$18 million of additional compression units and serialized parts, all of which USAC expects to be delivered throughout ~~2019 and~~ 2020.

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 for our and 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 net changes in operating assets and liabilities (net of effects

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of acquisitions). Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers.

~~Nine~~Six months ended ~~September~~June 30, ~~2019~~2020 compared to ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. Cash provided by operating activities during ~~2019~~2020 was ~~$6.06~~$3.38 billion compared to ~~$5.51 billion for 2018 and income from continuing operations was $3.79 billion and $3.07~~$4.02 billion for 2019, and ~~2018, respectively.~~net loss was $195 million for 2020 and net income was $2.50 billion for 2019. The difference between ~~income from continuing operations~~net loss and net cash provided by operating activities for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of ~~$325~~$27 million and other non-cash items totaling ~~$2.35~~$3.42 billion.

The non-cash activity in ~~2019~~2020 and ~~2018~~2019 consisted primarily of depreciation, depletion and amortization of ~~$2.33~~$1.80 billion and ~~$2.10~~$1.55 billion, respectively, non-cash compensation expense of ~~$85~~$63 million and ~~$82~~$58 million, respectively, inventory valuation adjustments of ~~$71~~$137 million and ~~$50~~$97 million, respectively, and deferred incomes taxes of ~~$193~~$126 million and $2$140 million, respectively. Non-cash activity also included losses on extinguishments of debt in 2020 and 2019 ~~and 2018~~ of $2$59 million and ~~$109~~$2 million, respectively, and impairment losses of ~~$62~~$1.33 billion and $50 million in ~~2019.~~2020 and 2019, respectively.

Unconsolidated affiliate activity in ~~2019~~2020 and ~~2018~~2019 consisted of equity in earnings of ~~$224~~$78 million and ~~$258~~$142 million, respectively, and cash distributions received of ~~$254~~$125 million and ~~$229~~$170 million, respectively.

Cash paid for interest, net of interest capitalized, ~~interest,~~ was ~~$1.44~~$1.05 billion and ~~$1.17~~$1.02 billion for the ~~nine~~six months ended ~~September~~June 30, 2020 and 2019, ~~and 2018,~~ respectively.

~~Capitalized interest~~ Interest capitalized was ~~$145~~$106 million and ~~$222~~$94 million for the ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018,~~2019, 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~~Six months ended ~~September~~June 30, ~~2019~~2020 compared to ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. Cash used in investing activities during ~~2019~~2020 was ~~$4.42~~$2.76 billion compared to ~~$4.51~~$2.94 billion in ~~2018.~~2019. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for ~~2019~~2020 were ~~$4.12~~$2.85 billion compared to ~~$5.08~~$2.78 billion for ~~2018.~~2019. 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. ~~During 2018, we received $711 million of net cash proceeds related to the USAC acquisition and paid $233 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~~six months ended ~~September~~June 30, ~~2019:~~2020:


	Capital Expenditures Recorded During Period						Capital Expenditures Recorded During Period
	Growth		Maintenance		Total		Growth		Maintenance		Total
Intrastate transportation and storage ⁽¹⁾	$	61	$	39	$	100	$	2	$	34	$	36
Interstate transportation and storage	194		95		289		22		34		56
Midstream	535		105		640		243		55		298
NGL and refined products transportation and services	1,956		69		2,025		1,340		39		1,379
Crude oil transportation and services	239		58		297		115		37		152
Investment in Sunoco LP	80		23		103		50		9		59
Investment in USAC	137		22		159		69		13		82
All other (including eliminations)	134		29		163		56		18		74
Total capital expenditures	$	3,336	$	440	$	3,776	$	1,897	$	239	$	2,136


⁽¹⁾	For the nine months ended September 30, 2019, growth capital expenditures for the intrastate transportation and storage segment reflect the proceeds received from the sale of a noncontrolling interest in the Red Bluff Express pipeline, which was based on capital expenditures from prior periods.

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.

~~Nine~~Six months ended ~~September~~June 30, ~~2019~~2020 compared to ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. Cash used in financing activities during ~~2019~~2020 was ~~$1.85 billion~~$750 million compared to ~~$3.67~~$1.05 billion for ~~2018.~~2019. During ~~2019,~~2020, we received net proceeds of ~~$780 million~~$1.58 billion from the issuance of preferred units. During 2018, we received net proceeds of $57 million from common unit issuances and net proceeds of $868 million from preferred unit issuances. During 2018, subsidiaries received net proceeds of $465 million from the issuance of redeemable noncontrolling interests. During 2019,2020, we had a net increase in our debt level of ~~$3.12 billion~~$934 million compared to a net ~~decrease~~increase of ~~$1.04~~$1.94 billion for ~~2018.~~2019. In ~~2019~~2020 and ~~2018,~~2019, we paid debt issuance costs of ~~$114~~$50 million and ~~$188~~$87 million, respectively.

In 2020 and 2019, we paid distributions of ~~$4.80~~$2.70 billion and $3.16 billion, respectively, to our ~~partners~~partners. In 2020 and ~~our subsidiaries~~2019, we paid distributions of ~~$1.11 billion~~$680 million and $731 million, respectively, to noncontrolling interests. In ~~2018,~~addition, we paid distributions of $3.14 billion to our partners and our subsidiaries paid distributions of $816 million to noncontrolling interests, including predecessor distributions. In addition, our subsidiaries received capital contributions of ~~$278~~$148 million in cash from noncontrolling interests in ~~2019~~2020 compared to ~~$438~~$206 million in ~~2018. During 2018, we repurchased common units for~~ cash ~~of $24 million and our subsidiaries also purchased $300 million of common units~~from noncontrolling interests in ~~cash.~~

~~Discontinued Operations~~

~~Cash flows from discontinued operations reflect cash flows related to Sunoco LP’s retail divestment.~~

~~Nine months ended September 30, 2019 compared to nine months ended September 30, 2018.~~ ~~There were no cash flows related to discontinued operations during~~ 2019. Cash provided by discontinued operations during 2018 was $2.74 billion, resulting from cash used in operating activities of $480 million, cash provided by investing activities of $3.21 billion and changes in cash included in current assets held for sale of $11 million.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	September 30, 2019			December 31, 2018			June 30, 2020			December 31, 2019
ETO Senior Notes ⁽¹⁾	$	36,117		$	28,755		$	37,783		$	36,118
Transwestern Senior Notes	575			575			400			575
Panhandle Senior Notes	236			385			235			235
Bakken Senior Notes	2,500			—			2,500			2,500
Sunoco LP Senior Notes and lease-related obligations	2,946			2,307			2,929			2,935
USAC Senior Notes	1,475			725			1,475			1,475
Credit facilities and commercial paper:
ETO $5.00 billion Revolving Credit Facility due December 2023 ⁽²⁾	2,608			3,694
Bakken Project $2.50 billion Credit Facility due August 2019	—			2,500
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⁾							3,010			4,214
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023	154			700			158			162
USAC $1.60 billion Revolving Credit Facility due April 2023	395			1,050			448			403
HFOTCO Tax Exempt Notes due 2050							225			225
SemCAMS Revolver due February 2024							92			92
SemCAMS Revolver Term Loan A due February 2024							251			269
Other long-term debt	4			7			11			2
Unamortized premiums, net of discounts and fair value adjustments	6			31
Net unamortized premiums, discounts, and fair value adjustments							(11		)	4
Deferred debt issuance costs	(286		)	(221		)	(293		)	(279		)
Total debt	46,730			40,508			51,213			50,930
Less: current maturities of long-term debt	14			2,655			34			25
Long-term debt, less current maturities	$	46,716		$	37,853		$	51,179		$	50,905

⁽¹⁾

The increase in ETO Senior Notes during nine months ended September 30, 2019 includes $4.21 billion issued in connection with the ET-ETO senior notes exchange and $4.00 billion issued in the January 2019 senior notes offering, both of which are discussed below. The September 30, 2019 balance also includes a $250 million aggregate principal amount of 5.50% senior notes due February 15, 2020 and a $400 million aggregate principal amount of 5.75% note due September 1, 2020 that were classified as long-term as of September 30, 2019 as management has the intent and ability to refinance the borrowing on a long-term basis.


⁽²⁾	Includes ~~$2.15~~$1.11 billion and ~~$2.34~~$1.64 billion of commercial paper outstanding at ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018,~~2019, respectively.

Recent Transactions

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 billion aggregate principal amount of the Partnership’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of the Partnership’s 3.750% Senior Notes due 2030 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 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.

Credit Facilities and Commercial Paper

ETO Term Loan

~~ET-ETO Senior Notes Exchange~~

In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO. Approximately 97% of ET’s outstanding senior notes were tendered and accepted, and substantially all the exchanges settled on March 25, 2019. In connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes:

~~$1.14 billion aggregate principal amount of 7.50% senior notes due 2020;~~

~~$995 million aggregate principal amount of 4.25% senior notes due 2023;~~June 30, 2020 was 1.18%.

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~~$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and~~

~~$956 million aggregate principal amount of 5.50% senior notes due 2027.~~

The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.

~~ETO Senior Notes Offering and Redemption~~

~~In January 2019, ETO issued the following senior notes:~~

~~$750 million aggregate principal amount of 4.50% senior notes due 2024;~~

~~$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and~~

~~$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.~~

~~ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019;~~

~~ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and~~

~~Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.~~

~~Panhandle Senior Notes Redemption~~

~~In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.~~

~~Bakken Senior Notes Offering~~

~~In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline:~~

~~$650 million aggregate principal amount of 3.625% senior notes due 2022;~~

~~$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and~~

~~$850 million aggregate principal amount of 4.625% senior notes due 2029.~~

~~The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.~~

~~Sunoco LP Senior Notes Offering~~

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~~its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms.~~

~~USAC Senior Notes Offering~~

~~Credit Facilities and Commercial Paper~~

ETO Five-Year Credit Facility

ETO 364-Day Facility

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”), which matures in July 2023. As of ~~September~~June 30, ~~2019,~~2020, the Sunoco LP Credit Facility had ~~$154~~$158 million of outstanding borrowings and $8 million in standby letters of credit. As of ~~September~~June 30, ~~2019~~2020, Sunoco LP had ~~$1.34~~$1.33 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of ~~September~~June 30, ~~2019~~2020 was ~~4.04%~~2.19%.

USAC Credit Facility

USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), with a further potential increase of $400 million, which matures in April 2023. As of ~~September~~June 30, ~~2019,~~2020, the USAC Credit Facility had ~~$395~~$448 million of outstanding borrowings and no outstanding letters of credit. As of ~~September~~June 30, ~~2019,~~2020, USAC had ~~$1.21~~$1.15 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of ~~$410~~$151 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of ~~September~~June 30, ~~2019~~2020 was ~~4.73%~~2.77%.

SemCAMS Credit Facilities

Covenants Related to Our Credit Agreements

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our ~~credit~~debt agreements as of ~~September~~June 30, ~~2019.~~2020.

Parent and Subsidiary Guarantee of Senior Notes

Sunoco Logistics Operations is the issuer of multiple series of senior notes that are guaranteed by ETO. Supplemental indentures were previously issued on all of the outstanding ETO senior notes to provide the guaranty by Sunoco Logistics Operations. These guarantees are full and unconditional on a senior unsecured basis. No other consolidated subsidiaries of the Partnership guarantee the senior notes. Neither Sunoco Logistics Operations nor ETO have material independent assets or operations, other than their investments in and receivables from affiliates which are not subject to these guarantees.

Certain of ETO's and Sunoco Logistics Operations' subsidiaries are less than wholly-owned. Consequently, such subsidiaries have noncontrolling interest holders whose rights and obligations are generally similar to ours, except in cases where redeemable and/or preferred noncontrolling interests exist. Additional information and balances related to noncontrolling interests are available in the consolidated financial statements and notes thereto included in "Item 1. Financial Statements" in this quarterly report on Form 10-Q and in "Item 8. Financial Statements and Supplementary Data" included in our annual report on Form 10-K.

In addition, because none of ETO’s or Sunoco Logistics Operations’ other subsidiaries guarantee the senior notes, the senior notes are structurally subordinated to the claims of all creditors, including unsecured indebtedness, trade creditors and tort claimants,

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of those subsidiaries. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of any of our subsidiaries (except for Sunoco Logistics Operations), creditors of such subsidiaries would generally have the right to be paid in full before any distribution is made to us or the holders of the senior notes. As of June 30, 2020, our subsidiaries (other than Sunoco Logistics Operations) had an aggregate of $8.8 billion of indebtedness outstanding.

CASH DISTRIBUTIONS

Distributions on ETO’s preferred units declared and/or paid by the Partnership subsequent to December 31, ~~2018~~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		—		—


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


⁽²⁾	Series EF Preferred Unit and Series G Preferred Unit distributions related to the period ended ~~June 30, 2019~~March 31, 2020 represent a prorated initial distribution. Distributions are paid on a semi-annual basis.

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Sunoco LP Cash Distributions

Distributions declared and/or paid by Sunoco LP to its common unitholders subsequent to December 31, ~~2018~~2019 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2019	February 7, 2020	February 19, 2020	$	0.8255
March 31, 2020	May 7, 2020	May 19, 2020	0.8255
June 30, 2020	August 7, 2020	August 19, 2020	0.8255

USAC Cash Distributions

Distributions declared and/or paid by USAC to its common unitholders subsequent to December 31, ~~2018~~2019 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2019	January 27, 2020	February 7, 2020	$	0.5250
March 31, 2020	April 27, 2020	May 8, 2020	0.5250
June 30, 2020	July 31, 2020	August 10, 2020	0.5250

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 ~~22, 2019.~~21, 2020. See Note 1 in “Item 1. Financial Statements” for information regarding recent changes to the Partnership’s critical accounting policies related to ~~lease accounting.~~inventory.

RECENT ACCOUNTING PRONOUNCEMENTS

~~See Note 1~~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.

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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 ~~“Item 1. Financial Statements” included~~this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

•

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 limitation;


•	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;


•	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 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;


•	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 natural gas, NGL, refined products and crude oil production;


•	the availability of imported natural gas, NGLs, refined products and crude oil;

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•	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 natural gas, NGLs, refined products and crude oil;


•	availability of local, intrastate and interstate transportation systems;


•	the continued ability to find and contract for new sources of natural gas supply;


•	availability and marketing of competitive fuels;


•	the impact of energy conservation efforts;


•	energy efficiencies and technological trends;


•	governmental regulation and taxation;


•	changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;


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


•	competition from other midstream companies and interstate pipeline companies;


•	loss of key personnel;


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


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


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


•	the nonpayment or nonperformance by our subsidiaries’ customers;


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


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


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


•	a deterioration of the credit and capital markets;


•	risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;


•	the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;


•	changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and


•	the costs and effects of legal and administrative proceedings.

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 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.

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, “Part II - Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and “Part II - Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information ~~regarding recent accounting pronouncements.~~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 7A7A. included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 filed with the SEC on February ~~22, 2019,~~21, 2020, 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 for the year ended December 31, ~~2018.~~2019. Since December 31, ~~2018~~2019, 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, 2019							December 31, 2018							June 30, 2020							December 31, 2019
	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
(Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX ⁽¹⁾	20,563		$	(2	)	$	5	16,845		$	7		$	1	(20,433	)	$	10		$	4	(35,208	)	$	2		$	5
Fixed Swaps/Futures	1,723		—			—		468		—			—		373		—			—		1,483		—			—
Options – Puts	—		—			—		10,000		—			—
Power (Megawatt):
Forwards	2,847,350		7			7		3,141,520		6			8		1,338,776		4			3		3,213,450		6			8
Futures	222,440		(1		)	—		56,656		—			—		204,090		—			1		(353,527	)	1			2
Options – Puts	515,317		—			—		18,400		—			—		(340,743	)	1			—		51,615		1			—
Options – Calls	(756,153	)	(1		)	—		284,800		1			—		(1,268,532	)	1			—		(2,704,330	)	1			—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(23,653	)	(26		)	16		(30,228	)	(52		)	13		(27,713	)	19			8		(18,923	)	(35		)	15
Swing Swaps IFERC	22,365		(4		)	2		54,158		12			—		(35,590	)	(3		)	8		(9,265	)	—			4
Fixed Swaps/Futures	2,323		1			—		(1,068	)	19			1		(10,708	)	(20		)	20		(3,085	)	(1		)	1
Forward Physical Contracts	(29,492	)	3			7		(123,254	)	(1		)	32		(23,980	)	6			6		(13,364	)	3			3
NGLs (MBbls) – Forwards/Swaps	(9,687	)	50			46		(2,135	)	67			67		(8,830	)	(10		)	20		(1,300	)	(18		)	18
Refined Products (MBbls) – Futures	(906	)	(2		)	5		(1,403	)	(8		)	6		(3,370	)	(17		)	1		(2,473	)	(2		)	16
Crude (MBbls) – Forwards/Swaps	9,510		42			4		20,888		(60		)	29		3,393		2			—		4,465		13			2
Corn (thousand bushels)	(1,760	)	—			1		(1,920	)	—			1		—		—			—		(1,210	)	—			—
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(31,703	)	1			8		(17,445	)	(4		)	—		(43,235	)	—			10		(31,780	)	1			7
Fixed Swaps/Futures	(31,703	)	14			8		(17,445	)	(10		)	6		(43,235	)	(4		)	11		(31,780	)	23			7


⁽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 financial

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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~~June 30, ~~2019~~2020, we had ~~$3.76~~$6.78 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of ~~$38~~$68 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of

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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
Term	Type⁽¹⁾	June 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


⁽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 interest rate swaps were terminated in January 2020.

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 ~~$362~~$311 million as of ~~September~~June 30, ~~2019.~~2020. 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 Executive Officer (“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 and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2019~~2020 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During thethree months ended ~~September~~June 30, ~~2019, the Partnership, including~~2020, certain of ~~its~~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.

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Other than as discussed above, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during thethree months ended ~~September~~June 30, ~~2019~~ 2020that have materially affected, or are reasonably likely to materially affect, our internal controls 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 ~~22, 2019~~21, 2020 and Note 10 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Operating, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended ~~September~~June 30, ~~2019.~~2020.

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 result in monetary sanctions in excess of $100,000.

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.

On February 8, 2019, PADEP filed a Petition to Enforce the Compliance Order with Pennsylvania’s Commonwealth Court. The court issued an Order on February 14, 2019 requiring the submission of an answer to the Petition on or before March 12, 2019, and scheduled a hearing on the Petition for March 26, 2019. On March 12, 2019, ETC Northeast answered the Petition. ETC Northeast and PADEP have since agreed to a Stipulated Order regarding the issues raised in the Compliance Order, which obviated the need for a hearing. The Commonwealth Court approved the Stipulated Order on March 26, 2019. On February 8, 2019, PADEP also issued a Permit Hold on any requests for approvals/permits or permit amendments made by us or any of our subsidiaries for any projects 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 March 11, 2019. On May 14, 2019, PADEP issued a Compliance Order related to impacts to streams and wetlands. The Partnership filed an appeal of the Streams and Wetlands Compliance Order on June 14, 2019. On August 5, 2019, ETC Northeast and the Partnership received a Subpoena to Compel Documents and Information related to the Revolution pipeline and the Incident. ETC Northeast and the Partnership filed an appeal of the Subpoena on September 4, 2019.

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” 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.

For a description of other legal proceedings, see Note 10 to our consolidated financial statements included in “Item 1. Financial Statements.”

ITEM 1A. RISK FACTORS

~~There have been no material changes from the~~The following risk factors should be read in conjunction with our risk factors described in ~~Part~~"Part I - Item 1A1A. Risk Factors" in the ~~Partnership’s~~Partnership's Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 filed with the SEC on February ~~22, 2019.~~21, 2020 and from the risk factors described in "Part II - Item 1A. Risk Factors" in the Partnership's Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 11, 2020.

Legal or regulatory actions related to the Dakota Access Pipeline could cause an interruption to current or future operations, which could have an adverse effect on our business and results of operations.

On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia challenging permits issued by the United States Army Corps of Engineers (“USACE”) permitting 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 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”). Plaintiffs and Defendants filed cross motions for summary judgment. 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 have filed notices of appeal with the United States Court of Appeals for the District of Columbia (“Court of Appeals”) with respect to the Court’s ruling related to the preparation of an Environmental Impact Statement and also filed motions for a stay of the Court’s July 6, 2020 Order. On July 14, 2020, the Court of Appeals administratively stayed the Court’s July 6 Order and ordered further briefing with respect to the motion to stay. 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 stay of the March 25 Order and the remaining portion of the July 6 Order vacating the easement. As a result, no court order stops Dakota Access from continuing to operate the Pipeline. The August 5 Order contemplates that the USACE will make a determination under its regulations and procedures whether vacating the easement requires oil to stop flowing. The Order also contemplates further proceedings in the District Court, and it expedites the appeal with briefing to conclude by September 30, 2020.

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

In addition, lawsuits 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.

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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
3.1		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1, File No. 333-71968, filed October 22, 2001)
3.2		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed September 1, 2015)
3.3		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, File No. 1-31219, filed April 28, 2017)
3.4		~~3.4~~Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (formerly known as Sunoco Logistics Partners L.P.) (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, File No. 1-31219, filed April 28, 2017)
3.5		Certificate of Merger of Streamline Merger Sub, LLC, with and into Energy Transfer Partners, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed October 19, 2018)
3.6		~~3.5~~Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.14 to the Registrant’s Form 10-Q for the quarter ended March 31, 2010)
3.7		Certificate of Formation of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13 to the Registrant’s Form 10-Q for the quarter ended March 31, 2010)
3.8		Certificate of Amendment of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2010)
3.9		Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, File No. 1-31219, filed October 19, 2018)
~~3.5.1~~ 3.10		Amendment No. 1, dated as of December 31, 2018, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed January 4, 2019)
~~3.5.2~~ 3.11		Amendment No. 2, dated as of April 25, 2019, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed April 25, 2019)
~~3.5.3~~ 3.12		Amendment No. 3, dated as of July 1, 2019, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer Operating, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed July 2, 2019)
~~10.1~~ 3.13		~~Term Loan Credit~~Amendment No. 4 to Fifth Amended and Restated Agreement ~~dated as~~ of ~~October 17, 2019 among~~Limited Partnership of Energy Transfer Operating, L.P.~~, Toronto Dominion (Texas) LLC, as Administrative Agent, the other lenders party thereto and the other parties named therein~~ (incorporated by reference to Exhibit ~~10.1~~3.1 to the Current Report on Form 8-K File No. 1-31219, filed ~~October 18, 2019)~~January 22, 2020)
~~10.2~~ 3.14		~~Guaranty dated as~~Amendment No. 5 to Fifth Amended and Restated Agreement of ~~October 17, 2019 between Sunoco Logistics Partners Operations~~Limited Partnership of Energy Transfer Operating, L.P. ~~and Toronto Dominion (Texas) LLC, as Administrative Agent~~ (incorporated by reference to Exhibit ~~10.2~~3.1 to the Current Report on Form 8-K File No. 1-31219, filed ~~October 18, 2019)~~May 5, 2020)
3.15		31.1*Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P., dated as of April 17, 2007 (incorporated by reference to Exhibit 3.5 to the Registrant’s Form 10-Q for the quarter ended May 31, 2007)
3.16		Amendment No. 2, dated March 26, 2012, to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K, File No. 1-31219, filed March 28, 2012)
3.17		Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, File No. 1-31219, filed August 10, 2010)
3.18		Amendment No. 1, dated March 26, 2012, to the Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C., dated as of August 10, 2010 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, File No. 1-31219, filed March 28, 2012)

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4.1		Fourth Supplemental Indenture, dated as of January 22, 2020, by and among Energy Transfer Operating, L.P., as issuer, Sunoco Logistics Partners Operations L.P., as guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2. to the Current Report on Form 8-K, File No. 1-31219, filed January 22, 2020)
4.2		Forms of Notes (included in Exhibit 4.1 hereto, incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K, File No. 1-31219, filed January 22, 2020)
22.1		Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2020)
31.1*		Certification of 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 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 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 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.SCH101		~~XBRL Taxonomy Extension Schema Document~~
101.CAL*		~~XBRL Taxonomy Extension Calculation Linkbase Document~~
101.DEF*		~~XBRL Taxonomy Extension Definition Linkbase Document~~
101.LAB*		~~XBRL Taxonomy Extension Label Linkbase Document~~
101.PRE*		~~XBRL Taxonomy Extension Presentation Linkbase Document~~Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019; (ii) our Consolidated Statements of Operations for the three and six months ended June 30, 2020 and 2019; (iii) our Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2020 and 2019; (iv) our Consolidated Statements of Partners’ Capital for the three and six months ended June 30, 2020 and 2019; (v) our Consolidated Statements of Cash Flows for the six months ended June 30, 2020 and 2019; and (vi) the notes to our Consolidated Financial Statements.
104		Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)



*		Filed herewith.
**		Furnished herewith.

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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 OPERATING, L.P.

		By:	Energy Transfer Partners GP, L.P.,
			its general partner

		By:	Energy Transfer Partners, L.L.C.,
			its general partner

Date:	~~November 7, 2019~~August 6, 2020	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)

7870



PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets	1

Consolidated Statements of Operations	3

Consolidated Statements of Comprehensive Income (Loss)	4

Consolidated Statements of Equity	5

Consolidated Statements of Cash Flows	7

Notes to Consolidated Financial Statements	8

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	5037

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	7364

ITEM 4. CONTROLS AND PROCEDURES	7565

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	7667

ITEM 1A. RISK FACTORS	7667

ITEM 6. EXHIBITS	7768

SIGNATURE	7870



	Balance at December 31, 2018, as previously reported		Adjustments due to Topic 842 (Leases)			Balance at January 1, 2019
Assets:
Property, plant and equipment, net	$	66,655	$	(1	)	$	66,654
Lease right-of-use assets, net	—		889			889
Liabilities:
Operating lease current liabilities	$	—	$	71		$	71
Accrued and other current liabilities	2,847		(1		)	2,846
Current maturities of long-term debt	2,655		1			2,656
Long-term debt, less current maturities	37,853		6			37,859
Non-current operating lease liabilities	—		823			823
Other non-current liabilities	1,184		(12		)	1,172



	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
REVENUES	$	—		$	349

COSTS AND EXPENSES
Cost of products sold	—			305
Operating expenses	—			61
Selling, general and administrative	—			7
Total costs and expenses	—			373
OPERATING LOSS	—			(24		)
Interest expense, net	—			(2		)
Loss on extinguishment of debt and other	—			(20		)
Other, net	—			(61		)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	—			(107		)
Income tax expense	2			158
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(2	)	$	(265	)



	Years Ending December 31,
	2019 (remainder)		2020		2021		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2019	$	1,716	$	5,544	$	4,812	$	29,062	$	41,134



	September 30, 2019
Operating leases:
Lease right-of-use assets, net	$	850
Operating lease current liabilities	57
Accrued and other current liabilities	1
Non-current operating lease liabilities	807
Finance leases:
Property, plant and equipment, net	$	2
Lease right-of-use assets, net	39
Accrued and other current liabilities	1
Current maturities of long-term debt	7
Long-term debt, less current maturities	35
Other non-current liabilities	2



	Income Statement Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease costs:
Operating lease cost	Cost of goods sold	$	7	$	23
Operating lease cost	Operating expenses	18		54
Operating lease cost	Selling, general and administrative	3		10
Total operating lease costs		28		87
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	2		4
Interest on lease liabilities	Interest expense, net of capitalized interest	1		1
Total finance lease costs		3		5
Short-term lease cost	Operating expenses	10		33
Variable lease cost	Operating expenses	3		11
Lease costs, gross		44		136
Less: Sublease income	Other revenue	14		37
Lease costs, net		$	30	$	99



	Nine Months Ended September 30, 2019
Operating cash flows from operating leases	$	(78	)
Lease assets obtained in exchange for new finance lease liabilities	37
Lease assets obtained in exchange for new operating lease liabilities	36



	Operating Leases		Finance Leases		Total
2019 (remainder)	$	27	$	2	$	29
2020	96		10		106
2021	87		10		97
2022	75		10		85
2023	70		9		79
Thereafter	1,170		10		1,180
Total lease payments	1,525		51		1,576
Less: present value discount	660		6		666
Present value of lease liabilities	$	865	$	45	$	910



	Lease Receivables
2019 (remainder)	$	25
2020	85
2021	69
2022	56
2023	4
Thereafter	7
Total undiscounted cash flows	$	246



	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended September 30,				Nine Months Ended September 30,
		2019		2018		2019		2018
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	—	$	—	$	—	$	9



	September 30, 2019
	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—	$	—	$	207	$	—		$	207
Accounts receivable, related parties	4,467		43,654		73,807		(121,704		)	224
All other current assets	—		—		6,724		—			6,724
Property, plant and equipment, net	—		—		68,870		—			68,870
Investments in unconsolidated affiliates	56,270		14,838		3,065		(71,186		)	2,987
All other assets	3,560		131		12,544		—			16,235
Total assets	$	64,297	$	58,623	$	165,217	$	(192,890	)	$	95,247

Accounts payable, related parties	$	2,725	$	40,512	$	76,876	$	(120,090	)	$	23
Other current liabilities	654		140		6,205		—			6,999
Non-current liabilities	31,260		7,603		13,751		—			52,614
Noncontrolling interests	—		—		7,974		—			7,974
Total partners’ capital	29,658		10,368		60,411		(72,800		)	27,637
Total liabilities and equity	$	64,297	$	58,623	$	165,217	$	(192,890	)	$	95,247

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