UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, ~~2018~~2019



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

Commission file number 1-31219

~~ENERGY TRANSFER OPERATING,~~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, Texas75225

(Address of principal executive offices) (zip code)

~~(214) 981-0700~~

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

~~Energy Transfer Partners, L.P.~~

~~(Former name, former address and former fiscal year, if changed since last report)~~

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. Yesý 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). Yesý 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¨☐Noý

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

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Operating, L.P. (the “Partnership” or ~~“ETP”~~“ETO”) in periodic press releases and some oral statements of 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, ~~2017~~2018 filed with the Securities and Exchange Commission on February 23, 2018, “Part II – Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 filed on May 10, 2018 and “Part II – Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed on August 9, 2018.22, 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

	~~Capacity~~		capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

	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

	~~ETC OLP~~ET		~~La Grange Acquisition, L.P., which conducts business under the assumed name of~~ Energy Transfer ~~Company~~LP, a publicly traded partnership and the owner of ETP LLC

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

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

	~~ETP Holdco~~		~~ETP Holdco Corporation~~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

	GAAP		accounting principles generally accepted in the United States of America

	~~HPC~~		~~RIGS Haynesville Partnership Co.~~

	IDRs		incentive distribution rights

~~Table of Contents~~



	Lake Charles LNG		Lake Charles LNG Company, LLC

	~~Legacy ETP Preferred Units~~		~~legacy ETP Series A cumulative convertible preferred units~~ (previously named Trunkline LNG Company, LLC)

	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

	~~PennTex~~PES		~~PennTex Midstream Partners, LP~~Philadelphia Energy Solutions Refining and Marketing LLC

	~~PES~~Preferred Unitholders		~~Philadelphia Energy Solutions~~Unitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units and Series E Preferred Units, collectively

	Regency		Regency Energy Partners LP

	~~Retail Holdings~~		~~ETP Retail Holdings, LLC, a wholly-owned subsidiary of Sunoco, Inc.~~

	RIGS		Regency Intrastate Gas LPSystem

	Rover		Rover Pipeline LLC, a subsidiary of ~~ETP~~ETO

	SEC		Securities and Exchange Commission

	SemGroup		SemGroup Corporation

	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

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

	SPLP		Sunoco ~~Logistics Partners~~Pipeline L.P.

	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

	Trunkline		Trunkline Gas Company, LLC, a subsidiary of Panhandle

	UGI		UGI Corporation

	USAC		USA Compression Partners, LP

	USAC Preferred Units		USAC Series A Preferred Units

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments. Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

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, 2018			December 31, 2017			September 30, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	379		$	306		$	207		$	418
Accounts receivable, net	3,671			3,946			4,368			4,009
Accounts receivable from related companies	333			318			224			176
Inventories	1,507			1,589			1,814			1,677
Income taxes receivable	169			135			109			73
Derivative assets	93			24			56			111
Other current assets	201			210			377			356
Total current assets	6,353			6,528			7,155			6,820

Property, plant and equipment	70,966			67,699			83,537			79,280
Accumulated depreciation and depletion	(10,416		)	(9,262		)	(14,667		)	(12,625		)
	60,550			58,437			68,870			66,655

Advances to and investments in unconsolidated affiliates	3,599			3,816			2,987			2,636
Lease right-of-use assets, net							889			—
Other non-current assets, net	863			758			1,089			1,006
Notes receivable from related company							3,606			440
Intangible assets, net	4,925			5,311			5,781			6,000
Goodwill	2,866			3,115			4,870			4,885
Total assets	$	79,156		$	77,965		$	95,247		$	88,442

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)


	September 30, 2018		December 31, 2017		September 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,381	$	4,126	$	3,519		$	3,491
Accounts payable to related companies	287		209		23			119
Derivative liabilities	338		109		181			185
Operating lease current liabilities					57			—
Accrued and other current liabilities	2,603		2,143		3,228			2,847
Current maturities of long-term debt	2,649		407		14			2,655
Total current liabilities	9,258		6,994		7,022			9,297

Long-term debt, less current maturities	31,198		32,687		46,716			37,853
Non-current derivative liabilities	57		145		360			104
Non-current operating lease liabilities					807			—
Deferred income taxes	2,845		2,883		3,094			2,884
Other non-current liabilities	1,100		1,084		1,138			1,184
					��
Commitments and contingencies
Redeemable noncontrolling interests	22		21		499			499

Equity:
Limited Partners:
Series A Preferred Unitholders	944		944
Series B Preferred Unitholders	547		547
Series C Preferred Unitholders	439		—
Series D Preferred Unitholders	436		—
Preferred Unitholders					3,151			2,388
Common Unitholders	25,628		26,531		24,526			26,372
General Partner	340		244
Accumulated other comprehensive income	8		3
Accumulated other comprehensive loss					(40		)	(42		)
Total partners’ capital	28,342		28,269		27,637			28,718
Noncontrolling interest	6,334		5,882
Noncontrolling interests					7,974			7,903
Total equity	34,676		34,151		35,611			36,621
Total liabilities and equity	$	79,156	$	77,965	$	95,247		$	88,442

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,
2018 2017* 2018 2017*
REVENUES:
Natural gas sales $ 1,026
$ 1,098
$ 3,112
$ 3,132
NGL sales 2,695
1,750
6,866
4,782
Crude sales 3,841
2,381
11,336
7,268
Gathering, transportation and other fees 1,579
1,027
4,440
3,118
Refined product sales 382
334
1,234
1,109
Other 118
383
343
1,035
Total revenues 9,641
6,973
27,331
20,444
COSTS AND EXPENSES:
Cost of products sold 6,745
4,922
19,873
14,595
Operating expenses 632
571
1,863
1,603
Depreciation, depletion and amortization 636
596
1,827
1,713
Selling, general and administrative 123
105
347
335
Total costs and expenses 8,136
6,194
23,910
18,246
OPERATING INCOME 1,505
779
3,421
2,198
OTHER INCOME (EXPENSE):
Interest expense, net (387 ) (352 ) (1,091 ) (1,020 )
Equity in earnings of unconsolidated affiliates 113
127
147
139
Gain on Sunoco LP common unit repurchase —
—
172
—
Loss on deconsolidation of CDM —
—
(86 ) —
Gains (losses) on interest rate derivatives 45
(8 ) 117
(28 )
Other, net 21
57
127
137
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) 1,297
603
2,807
1,426
Income tax expense (benefit) (61 ) (112 ) (32 ) 22
NET INCOME 1,358
715
2,839
1,404
Less: Net income attributable to noncontrolling interest 223
110
557
266
NET INCOME ATTRIBUTABLE TO PARTNERS $ 1,135
$ 605
$ 2,282
$ 1,138

* As adjusted. See Note 1.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
REVENUES:
Refined product sales	$	4,311		$	4,777		$	12,514		$	12,980
Crude sales	3,971			3,844			11,842			11,344
NGL sales	1,723			2,870			6,121			7,461
Gathering, transportation and other fees	2,466			1,781			6,768			4,878
Natural gas sales	822			1,026			2,549			3,112
Other	202			216			699			739
Total revenues	13,495			14,514			40,493			40,514
COSTS AND EXPENSES:
Cost of products sold	9,890			11,093			29,607			31,681
Operating expenses	806			784			2,406			2,280
Depreciation, depletion and amortization	782			747			2,334			2,100
Selling, general and administrative	171			175			495			495
Impairment losses	12			—			62			—
Total costs and expenses	11,661			12,799			34,904			36,556
OPERATING INCOME	1,834			1,715			5,589			3,958
OTHER INCOME (EXPENSE):
Interest expense, net of capitalized interest	(575		)	(446		)	(1,680		)	(1,246		)
Equity in earnings of unconsolidated affiliates	82			87			224			258
Losses on extinguishments of debt	—			—			(2		)	(109		)
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Other, net	113			40			242			96
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
Less: Net income attributable to noncontrolling interests	261			223			783			557
Less: Net income attributable to redeemable noncontrolling interests	12			—			38			—
Less: Net income (loss) attributable to predecessor equity	—			133			—			(37		)
NET INCOME ATTRIBUTABLE TO PARTNERS	$	951		$	1,135		$	2,965		$	2,282

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017* 2018 2017*
Net income $ 1,358
$ 715
$ 2,839
$ 1,404
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities 2
2
—
5
Actuarial gain (loss) relating to pension and other postretirement benefit plans —
5
(2 ) 2
Change in other comprehensive income from unconsolidated affiliates 2
—
9
(1 )
4
7
7
6
Comprehensive income 1,362
722
2,846
1,410
Less: Comprehensive income attributable to noncontrolling interest 223
110
557
266
Comprehensive income attributable to partners $ 1,139
$ 612
$ 2,289
$ 1,144

* As adjusted. See Note 1.



	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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF EQUITY

~~FOR THE~~ ~~NINE~~ ~~MONTHS ENDED~~ ~~SEPTEMBER 30, 2018~~

(Dollars in millions)

(unaudited)

Limited Partners
Series A Preferred Units Series B Preferred Units Series C Preferred Units Series D Preferred Units Common Units General Partner AOCI Noncontrolling Interest Total
Balance, December 31, 2017 $ 944
$ 547
$ —
$ —
$ 26,531
$ 244
$ 3
$ 5,882
$ 34,151
Distributions to partners (44 ) (27 ) (10 ) —
(1,975 ) (1,080 ) —
—
(3,136 )
Distributions to noncontrolling interest —
—
—
—
—
—
—
(536 ) (536 )
Units issued for cash —
—
436
431
58
—
—
—
925
Capital contributions from noncontrolling interest —
—
—
—
—
—
—
438
438
Repurchases of common units —
—
—
—
(24 ) —
—
—
(24 )
Other comprehensive income, net of tax —
—
—
—
—
—
7
—
7
Other, net (1 ) —
(1 ) (1 ) 41
(17 ) (2 ) (7 ) 12
Net income 45
27
14
6
997
1,193
—
557
2,839
Balance, September 30, 2018 $ 944
$ 547
$ 439
$ 436
$ 25,628
$ 340
$ 8
$ 6,334
$ 34,676



	Limited Partners
	Preferred Unitholders			Common Unitholders			AOCI			Non-controlling Interests			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
Distributions to partners	(18		)	(1,625		)	—			—			(1,643		)
Distributions to noncontrolling interests	—			—			—			(370		)	(370		)
Units issued for cash	780			—			—			—			780
Capital contributions from noncontrolling interests	—			—			—			66			66
Other comprehensive income, net of tax	—			—			1			—			1
Other, net	(1		)	(36		)	—			—			(37		)
Net income, excluding amounts attributable to redeemable noncontrolling interests	53			949			—			266			1,268
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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in millions)

(unaudited)



	Limited Partners
	Preferred Unitholders			Common Unitholders			General Partner			AOCI			Non-controlling Interests			Predecessor Equity			Total
Balance, December 31, 2017	$	1,491		$	26,531		$	244		$	3		$	5,882		$	2,816		$	36,967
Distributions to partners	(24		)	(657		)	(264		)	—			—			—			(945		)
Distributions to noncontrolling interests	—			—			—			—			(183		)	(70		)	(253		)
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
Cumulative effect adjustment due to change in accounting principle	—			—			—			—			—			(54		)	(54		)
Other comprehensive income, net of tax	—			—			—			1			—			—			1
Other, net	(2		)	(16		)	(17		)	(2		)	(6		)	1			(42		)
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
Distributions to partners	(57		)	(660		)	(408		)	—			—			—			(1,125		)
Distributions to noncontrolling interests	—			—			—			—			(177		)	(101		)	(278		)
Units issued for cash	431			19			—			—			—			—			450
Capital contributions from noncontrolling interests	—			—			—			—			120			—			120
Other comprehensive income, net of tax	—			—			—			4			—			—			4
Other, net	(2		)	15			—			—			(3		)	5			15
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

ENERGY TRANSFER OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

Nine Months Ended
September 30,
2018 2017*
OPERATING ACTIVITIES
Net income $ 2,839
$ 1,404
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization 1,827
1,713
Deferred income taxes (17 ) (1 )
Non-cash compensation expense 61
57
Gain on Sunoco LP common unit repurchase (172 ) —
Loss on deconsolidation of CDM 86
—
Distributions on unvested awards (24 ) (21 )
Equity in earnings of unconsolidated affiliates (147 ) (139 )
Distributions from unconsolidated affiliates 328
319
Other non-cash (132 ) (163 )
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations 451
168
Net cash provided by operating activities 5,100
3,337
INVESTING ACTIVITIES
Cash proceeds from CDM contribution 1,227
—
Cash proceeds from Sunoco LP common unit repurchase 540
—
Cash proceeds from Bakken pipeline transaction —
2,000
Cash paid for acquisition of PennTex noncontrolling interest —
(280 )
Cash paid for all other acquisitions (29 ) (264 )
Capital expenditures, excluding allowance for equity funds used during construction (4,962 ) (6,074 )
Contributions in aid of construction costs 95
18
Contributions to unconsolidated affiliates (13 ) (230 )
Distributions from unconsolidated affiliates in excess of cumulative earnings 62
116
Proceeds from the sale of assets 13
33
Other —
(6 )
Net cash used in investing activities (3,067 ) (4,687 )
FINANCING ACTIVITIES
Proceeds from borrowings 16,930
19,978
Repayments of debt (16,520 ) (18,487 )
Cash paid to affiliate notes —
(255 )
Common units issued for cash 58
2,162
Preferred units issued for cash 867
—
Capital contributions from noncontrolling interest 438
919
Distributions to partners (3,136 ) (2,543 )
Distributions to noncontrolling interest (536 ) (306 )
Repurchases of common units (24 ) —
Redemption of Legacy ETP Preferred Units —
(53 )
Debt issuance costs (42 ) (50 )
Other 5
4
Net cash (used in) provided by financing activities (1,960 ) 1,369
Increase in cash and cash equivalents 73
19
Cash and cash equivalents, beginning of period 306
360
Cash and cash equivalents, end of period $ 379
$ 379

* As adjusted. See Note 1.



	Nine Months Ended September 30,
	2019			2018
OPERATING ACTIVITIES
Net income	$	3,786		$	2,802
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	—			265
Depreciation, depletion and amortization	2,334			2,100
Deferred income taxes	193			2
Inventory valuation adjustments	(71		)	(50		)
Non-cash compensation expense	85			82
Impairment losses	62			—
Losses on extinguishments of debt	2			109
Distributions on unvested awards	(5		)	(36		)
Equity in earnings of unconsolidated affiliates	(224		)	(258		)
Distributions from unconsolidated affiliates	254			229
Other non-cash	(29		)	(93		)
Net change in operating assets and liabilities, net of effects of acquisitions	(325		)	358
Net cash provided by operating activities	6,062			5,510
INVESTING ACTIVITIES
Cash proceeds from sale of noncontrolling interest in subsidiary	93			—
Cash proceeds from USAC acquisition, net of cash received	—			711
Cash paid for all other acquisitions, net of cash received	(7		)	(233		)
Capital expenditures, excluding allowance for equity funds used during construction	(4,181		)	(5,175		)
Contributions in aid of construction costs	63			95
Contributions to unconsolidated affiliates	(481		)	(13		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	40			62
Proceeds from the sale of other assets	55			40
Other	(5		)	—
Net cash used in investing activities	(4,423		)	(4,513		)
FINANCING ACTIVITIES
Proceeds from borrowings	18,125			21,713
Repayments of debt	(16,027		)	(22,620		)
Cash received from/paid to related company	1,018			(129		)
Common units issued for cash	—			57
Preferred units issued for cash	780			868
Redeemable noncontrolling interests issued for cash	—			465
Capital contributions from noncontrolling interests	278			438
Distributions to partners	(4,801		)	(3,136		)
Predecessor distributions to partners	—			(280		)
Distributions to noncontrolling interests	(1,105		)	(536		)
Distributions to redeemable noncontrolling interest	—			(12		)
Repurchases of common units	—			(24		)
Subsidiary repurchases of common units	—			(300		)
Debt issuance costs	(114		)	(188		)
Other	(4		)	11
Net cash used in financing activities	(1,850		)	(3,673		)
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
Cash and cash equivalents, beginning of period	418			335
Cash and cash equivalents, end of period	$	207		$	397

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, ~~Energy Transfer Equity, L.P. (“ETE”) and Energy Transfer Partners, L.P. (“ETP”)~~we completed the merger of ~~ETP~~ETO with a wholly-owned subsidiary of ~~ETE~~ET in a unit-for-unit exchange (the ~~“ETE-ETP~~“Energy Transfer Merger”). In connection with the transaction, ~~ETP~~ETO unitholders (other than ~~ETE~~ET and its subsidiaries) received 1.28 common units of ~~ETE~~ET for each common unit of ~~ETP~~ETO they owned.

~~Immediately prior to the closing of the ETE-ETP Merger, the following also occurred:~~

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

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

Following the closing of the ~~ETE-ETP~~Energy Transfer Merger, ~~ETE changed its name to “Energy~~Energy Transfer ~~LP”~~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 ~~Friday,~~ October 19, 2018. ~~In addition, ETP changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein:~~

~~References to “ETP” refer to the entity named Energy Transfer Partners, L.P.~~Immediately prior to the ~~close~~closing of ~~the ETE-ETP Merger and Energy Transfer Operating, L.P. subsequent to the close of the ETE-ETP Merger; and~~

~~References to “ETE” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the ETE-ETP Merger and Energy Transfer LP subsequent to the close of the ETE-ETP Merger.~~

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction (the “Sunoco Logistics Merger”), with the Energy Transfer ~~Partners, L.P. unitholders receiving 1.5~~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 to ETO in exchange 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 ~~Logistics~~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 ~~Partners, L.P.~~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 ~~unit they owned. In connection with the Sunoco Logistics Merger, Sunoco Logistics was renamed~~units.

The Energy Transfer ~~Partners, L.P.~~Merger was a combination of entities under common control; therefore, Sunoco LP, Lake Charles LNG and USAC’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation beginning January 1, 2018 for Sunoco ~~Logistics’ general partner was merged with~~LP and ~~into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.~~

The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legalLake Charles LNG and ~~reporting perspective. Therefore,~~Other and April 2, 2018 for ~~the pre-merger periods,~~USAC (the date ET acquired USAC). Predecessor equity included on the consolidated financial statements ~~reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.”~~represents Sunoco LP, Lake Charles LNG and Other and USAC’s equity prior to the ~~Sunoco Logistics Merger and related name changes).~~

The consolidated financial statements of the Partnership presented herein include our operating subsidiaries (collectively, the “Operating Companies”), through which our activities are primarily conducted, as follows:

ETC OLP, Regency and PennTex, which are primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP and Regency own and operate, through their wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, West Virginia, Colorado and Ohio.

Energy Transfer ~~Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which is the parent company of:~~

~~Transwestern, engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.~~

~~ETC Fayetteville Express Pipeline, LLC, which directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.~~

~~ETC Tiger Pipeline, LLC, engaged in interstate transportation of natural gas.~~

~~CrossCountry Energy, LLC, which indirectly owns a~~ ~~50%~~ ~~interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.~~

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~~ETC Midcontinent Express Pipeline, L.L.C., which directly owns a 50% interest in MEP.~~

~~ET Rover Pipeline, LLC, which ETIH directly owns a 50.1% interest in, which owns a 65% interest in the Rover pipeline.~~

~~ETC Compression, LLC, engaged in natural gas compression services and related equipment sales. As discussed further in Note 2 below, in April 2018, we contributed certain assets to USAC.~~

ETP Holdco, which indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. ETP Holdco also holds an equity method investment in ETP through its ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in ETP’s consolidated financial statements.

Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.Merger.

Our consolidated financial statements reflect the following reportable ~~business~~ 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.

~~Prior periods have been retrospectively adjusted to reflect the impact of the Sunoco Logistics Merger on our reportable business segments.~~

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 ~~Partners,~~Operating, L.P. for the year ended December 31, ~~2017,~~2018, included in the Partnership’s Annual Report on Form 10-K filed with the SEC on February ~~23, 2018.~~22, 2019. 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 ~~historical common unit amounts presented in these~~ consolidated financial statements ~~have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.~~

~~Change in Accounting Policy~~

~~Inventory Accounting Change~~

~~During the fourth quarter~~ of ~~2017,~~ the Partnership ~~elected~~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 change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferableconform to the ~~LIFO method as it more closely aligns the accounting policies across the consolidated entity.~~

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~~As a result of this change in accounting policy, the consolidated statement of operations and comprehensive~~current period presentation. These reclassifications had no impact on net income ~~in prior periods have been retrospectively adjusted, as follows:~~

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
As Originally Reported Effect of Change As Adjusted As Originally Reported Effect of Change As Adjusted
Cost of products sold $ 4,876
$ 46
$ 4,922
$ 14,582
$ 13
$ 14,595
Operating income 825
(46 ) 779
2,211
(13 ) 2,198
Income before income tax expense (benefit) 649
(46 ) 603
1,439
(13 ) 1,426
Net income 761
(46 ) 715
1,417
(13 ) 1,404
Net income attributable to partners 651
(46 ) 605
1,174
(36 ) 1,138
Comprehensive income 768
(46 ) 722
1,423
(13 ) 1,410
Comprehensive income attributable to partners 658
(46 ) 612
1,180
(36 ) 1,144

~~As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:~~

Nine Months Ended September 30, 2017
As Originally Reported Effect of Change As Adjusted
Net income $ 1,417
$ (13 ) $ 1,404
Inventory valuation adjustments (30 ) 30
—
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories) 185
(17 ) 168

~~Revenue Recognition Standard~~

~~In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods~~ or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018.

Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard.

Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018.

The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods.

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The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. There were no material changes in the timing of recognition of revenue and therefore no material impacts to the balance sheet upon adoption.

The disclosure below shows the impact of adopting the new standard during the period of adoption compared to amounts that would have been reported under the Partnership’s previous revenue recognition policies:

Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower) As Reported Balances Without Adoption of ASC 606 Effect of Change: Higher/(Lower)
Revenues:
Natural gas sales $ 1,026
$ 1,026
$ —
$ 3,112
$ 3,112
$ —
NGL sales 2,695
2,686
9
6,866
6,839
27
Crude sales 3,841
3,838
3
11,336
11,326
10
Gathering, transportation and other fees 1,579
1,783
(204 ) 4,440
4,977
(537 )
Refined product sales 382
381
1
1,234
1,233
1
Other 118
118
—
343
343
—

Costs and expenses:
Cost of products sold $ 6,745
$ 6,949
$ (204 ) $ 19,873
$ 20,410
$ (537 )
Operating expenses 632
619
13
1,863
1,825
38

~~Additional disclosures related to revenue are included in Note 11.~~total equity.

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

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

~~ASU 2016-02~~Adoption of Lease Accounting Standard

In February 2016, the ~~FASB~~Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which has amended the FASB Accounting Standards Codification (“~~ASU 2016-02”~~ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which ~~establishes~~is effective 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 ~~principles that lessees and lessors shall apply to report information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually~~balance sheet for all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”),with a term of more than one year, including operating leases, which ~~provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that~~historically were not previously accounted for as leases under the existing lease guidance in Topic 840. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standardrecorded on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leasesbalance sheet in accordance with the prior standard.

To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment 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 adoption 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 assets 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. ~~However, we~~

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 ~~still~~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 in the ~~process~~demand for storage on these assets, the Partnership performed an interim impairment test on the assets of ~~quantifying this impact. We expect that upon adoption most~~Southwest Gas during the three months ended September 30, 2019. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $12 million related to Southwest Gas, primarily due to decreases in projected future revenues and cash flows. No other impairments of the Partnership’s ~~lease commitments will be recognized as right of use~~other assets ~~and lease obligations.~~

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~~ASU 2017-12~~

~~In August 2017, the FASB issued Accounting Standards Update No. 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.~~ The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted.were identified. The Partnership estimated the fair value of Southwest Gas by using the income approach. The income approach is ~~currently evaluating the impact that adopting this new standard will have~~based on the ~~consolidated~~present value of future cash flows, which are derived from our long-term financial ~~statements~~forecasts, and ~~related disclosures.~~

~~ASU 2018-02~~

~~In February 2018, the FASB issued Accounting Standards Update No. 2018-02,~~ ~~Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows~~requires significant assumptions including, among others, a ~~reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts~~discount rate and ~~Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material.~~a terminal value.


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

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

On January 23, 2018, Sunoco LP completed the disposition of ~~Assets~~assets pursuant to ~~ETP~~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 from the Partnership’s consolidated balance sheets and are reported as accounts receivable.

~~Immediately prior~~In connection with the 7-Eleven Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated 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 the period from January 1, 2018 through January 22, 2018, Sunoco LP recorded sales to the sites 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 closing of the ~~ETE-ETP Merger discussed in Note 1, ETE contributed~~sale.

The Partnership has concluded that it meets the ~~following to ETP:~~

~~2,263,158 common units representing limited partner interests in Sunoco LP to ETP in exchange~~accounting requirements for ~~2,874,275 ETP common units;~~

~~100 percent~~reporting the financial position, results of ~~the limited liability company interests in Sunoco GP LLC, the sole general partner~~operations and cash flows of Sunoco ~~LP, and all of the IDRs in Sunoco LP, to ETP in exchange for 42,812,389 ETP common units;~~LP’s retail divestment as discontinued operations.

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 ETP in exchange for 16,134,903 ETP common units; and

a 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 ETP in exchange for 37,557,815 ETP common units.

ETP, Sunoco LP, USAC and Lake Charles LNG and Other are under common control of ETE; therefore, we expect to account for the contribution transactions at historical cost as a reorganization of entities under common control. Accordingly, beginning with the quarter ending December 31, 2018, ETP’s consolidated financial statements will be retrospectively adjusted to reflect consolidation of Sunoco LP and Lake Charles LNG and Other for all prior periods and consolidation of USAC subsequent to April 2, 2018 (the date ETE acquired USAC’s general partner).

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There were no results of operations associated with discontinued operations for the three and nine months ended September 30, 2019. The ~~following table summarizes~~results of operations associated with discontinued operations for the ~~assets~~three and ~~liabilities of Sunoco LP, USAC and Lake Charles LNG and Other as of~~nine months ended ended September 30, 2018 ~~which amounts will be retrospectively consolidated in ETP’s consolidated balance sheets beginning with the quarter ending December 31, 2018, subject to the elimination of intercompany balances:~~were as follows:



	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	)

Sunoco LP USAC Lake Charles LNG and Other
Current assets $ 1,331
$ 230
$ 28
Property, plant and equipment, net 1,494
2,541
746
Goodwill 1,534
619
184
Intangible assets 655
399
35
Other non-current assets 134
25
909
Total assets $ 5,148
$ 3,814
$ 1,902

Current liabilities $ 1,086
$ 173
$ 107
Long-term debt, less current maturities 2,774
1,731
—
Other non-current liabilities 343
6
8
Preferred Units —
477
—
Net assets $ 945
$ 1,427
$ 1,787

The unaudited financial information in the table below summarizes the combined results of our operations and those of Sunoco LP, USAC and Lake Charles LNG and Other on a pro forma basis, to reflect the retrospective consolidation of those entities. The pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved. The pro forma adjustments include the effect of intercompany revenue eliminations:

Unaudited Pro Forma
Nine Months Ended
September 30,
2018 2017
Revenues $ 40,514
$ 29,072
Net income attributable to partners $ 2,282
$ 1,138

~~CDM Contribution~~

On April 2, 2018, ETP contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019.

Prior to the CDM Contribution, the CDM entities were indirect wholly-owned subsidiaries of ETP. Beginning April 2018, ETP’s consolidated financial statements reflected an equity method investment in USAC. CDM’s assets and liabilities were not reflected as held for sale, nor were CDM’s results reflected as discontinued operations in these financial statements. At September 30, 2018, the carrying value of ETP’s investment in USAC was $385 million~~, which is reflected in the all other segment.~~ ~~ETP recorded an $86 million loss on the deconsolidation of CDM including a $45 million accrual related to the indemnification of USAC related to an ongoing CDM sales and use tax audit.~~

In connection with the CDM Contribution, ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC, and (ii) 12,466,912 USAC common units for cash consideration equal to $250 million.

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3.	~~ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES~~

~~HPC~~

ETP previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, ETP acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETP’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETP’s financial statements.

~~Sunoco LP~~

In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.

As of September 30, 2018, ETP owned 26.2 million Sunoco LP common units representing 31.8% of Sunoco LP’s total outstanding common units. Our investment in Sunoco LP is reflected in the all other segment. As of September 30, 2018, the carrying value of our investment in Sunoco LP was $542 million.

Subsequent to the ETE-ETP Merger, ETP owns 28.5 million Sunoco LP common units. For the periods presented herein, ETP’s investment in Sunoco LP is reflected under the equity method of accounting; however, for periods subsequent to the ETE-ETP Merger, ETP will reflect Sunoco LP as a consolidated subsidiary.

~~USAC~~

As of September 30, 2018, ETP owned 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests in USAC. USAC provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. Our investment in USAC is reflected in the all other segment. As of September 30, 2018, the carrying value of our investment in USAC was $385 million.

Subsequent to the ETE-ETP Merger, ETP owns 39.7 million USAC common units and 6.4 million USAC Class B Units. For the periods presented herein, ETP’s investment in USAC is reflected under the equity method of accounting; however, for periods subsequent to the ETE-ETP Merger, ETP will reflect USAC as a consolidated subsidiary.


4.3.	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 balance sheets did not include any material amounts of restricted cash as of September 30, 2019 or December 31, 2018.

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 and deconsolidations)~~acquisitions) included in cash flows from operating activities is comprised as follows:



	Nine Months Ended September 30,
	2019			2018
Accounts receivable	$	(353	)	$	152
Accounts receivable from related companies	(30		)	261
Inventories	(66		)	78
Other current assets	(14		)	(19		)
Other non-current assets, net	(182		)	(154		)
Accounts payable	27			(232		)
Accounts payable to related companies	(105		)	(227		)
Accrued and other current liabilities	194			406
Other non-current liabilities	(103		)	25
Derivative assets and liabilities, net	307			68
Net change in operating assets and liabilities, net of effects of acquisitions	$	(325	)	$	358

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Nine Months Ended
September 30,
2018 2017*
Accounts receivable $ 251
$ (77 )
Accounts receivable from related companies 206
46
Inventories 48
133
Other current assets (23 ) 37
Other non-current assets, net (99 ) (89 )
Accounts payable (177 ) 96
Accounts payable to related companies (199 ) (11 )
Accrued and other current liabilities 351
(26 )
Other non-current liabilities 21
57
Derivative assets and liabilities, net 72
2
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations $ 451
$ 168

* As adjusted. See Note 1.

Non-cash ~~investing and financing~~ activities are as follows:



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

Nine Months Ended
September 30,

2018 2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures $ 1,026
$ 1,236
USAC limited partner interests received in the CDM Contribution (see Note 2) 411
—
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest $ —
$ 988


5.4.	INVENTORIES

Inventories consisted of the following:



	September 30, 2019		December 31, 2018
Natural gas, NGLs and refined products	$	900	$	833
Crude oil	510		506
Spare parts and other	404		338
Total inventories	$	1,814	$	1,677

September 30, 2018 December 31, 2017
Natural gas, NGLs and refined products $ 615
$ 733
Crude oil 643
551
Spare parts and other 249
305
Total inventories $ 1,507
$ 1,589

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.


6.5.	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, ~~2018~~2019 was ~~$34.39~~$50.66 billion and ~~$33.85~~$46.73 billion, respectively. As of December 31, ~~2017,~~2018, the aggregate fair value and carrying amount of

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our consolidated debt obligations was ~~$34.28~~$39.54 billion and ~~$33.09~~$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 months ended September 30, ~~2018, no~~2019, 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 30, ~~2018~~2019 and December 31, ~~2017~~2018 based on inputs used to derive their fair values:


				Fair Value Measurements at September 30, 2018									Fair Value Measurements at September 30, 2019
	Fair Value Total			Level 1			Level 2			Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	48		$	48		$	—		$	27		$	27		$	—
Swing Swaps IFERC	1			—			1			5			—			5
Fixed Swaps/Futures	25			25			—			44			44			—
Forward Physical Contracts	12			—			12			5			—			5
Power:
Forwards	36			—			36			21			—			21
Options – Puts	1			1			—
Futures										4			4			—
NGLs – Forwards/Swaps	476			476			—			529			529			—
Refined Products – Futures										1			1			—
Crude – Forwards/Swaps										43			43			—
Total commodity derivatives	599			550			49			679			648			31
Other non-current assets	28			18			10			29			19			10
Total assets	$	627		$	568		$	59		$	708		$	667		$	41
Liabilities:
Interest rate derivatives	$	(97	)	$	—		$	(97	)	$	(528	)	$	—		$	(528	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(89		)	(89		)	—			(54		)	(54		)	—
Swing Swaps IFERC	(1		)	—			(1		)	(9		)	—			(9		)
Fixed Swaps/Futures	(26		)	(26		)	—			(29		)	(29		)	—
Forward Physical Contracts	(7		)	—			(7		)	(2		)	—			(2		)
Power:
Forwards	(30		)	—			(30		)	(14		)	—			(14		)
Futures	(1		)	(1		)	—			(5		)	(5		)	—
Options – Calls										(1		)	(1		)	—
NGLs – Forwards/Swaps	(521		)	(521		)	—			(479		)	(479		)	—
Refined Products – Futures	(5		)	(5		)	—			(3		)	(3		)	—
Crude – Forwards/Swaps	(190		)	(190		)	—			(1		)	(1		)	—
Total commodity derivatives	(870		)	(832		)	(38		)	(597		)	(572		)	(25		)
Total liabilities	$	(967	)	$	(832	)	$	(135	)	$	(1,125	)	$	(572	)	$	(553	)

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				Fair Value Measurements at December 31, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	42		$	42		$	—
Swing Swaps IFERC	52			8			44
Fixed Swaps/Futures	97			97			—
Forward Physical Contracts	20			—			20
Power:
Forwards	48			—			48
Futures	1			1			—
Options – Calls	1			1			—
NGLs – Forwards/Swaps	291			291			—
Refined Products – Futures	7			7			—
Crude – Forwards/Swaps	1			1			—
Total commodity derivatives	560			448			112
Other non-current assets	26			17			9
Total assets	$	586		$	465		$	121
Liabilities:
Interest rate derivatives	$	(163	)	$	—		$	(163	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(91		)	(91		)	—
Swing Swaps IFERC	(40		)	—			(40		)
Fixed Swaps/Futures	(88		)	(88		)	—
Forward Physical Contracts	(21		)	—			(21		)
Power:
Forwards	(42		)	—			(42		)
Futures	(1		)	(1		)	—
NGLs – Forwards/Swaps	(224		)	(224		)	—
Refined Products – Futures	(15		)	(15		)	—
Crude – Forwards/Swaps	(61		)	(61		)	—
Total commodity derivatives	(583		)	(480		)	(103		)
Total liabilities	$	(746	)	$	(480	)	$	(266	)

Fair Value Measurements at
December 31, 2017
Fair Value Total Level 1 Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX $ 11
$ 11
$ —
Swing Swaps IFERC 13
—
13
Fixed Swaps/Futures 70
70
—
Forward Physical Contracts 8
—
8
Power – Forwards 23
—
23
NGLs – Forwards/Swaps 191
191
—
Crude:
Forwards/Swaps 2
2
—
Futures 2
2
—
Total commodity derivatives 320
276
44
Other non-current assets 21
14
7
Total assets $ 341
$ 290
$ 51
Liabilities:
Interest rate derivatives $ (219 ) $ —
$ (219 )
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX (24 ) (24 ) —
Swing Swaps IFERC (15 ) (1 ) (14 )
Fixed Swaps/Futures (57 ) (57 ) —
Forward Physical Contracts (2 ) —
(2 )
Power – Forwards (22 ) —
(22 )
NGLs – Forwards/Swaps (186 ) (186 ) —
Refined Products – Futures (25 ) (25 ) —
Crude:
Forwards/Swaps (6 ) (6 ) —
Futures (1 ) (1 ) —
Total commodity derivatives (338 ) (300 ) (38 )
Total liabilities $ (557 ) $ (300 ) $ (257 )


7.6.	DEBT OBLIGATIONS

~~ETP~~Notes and Debentures

ET-ETO Senior Notes ~~Offering~~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 tendered and ~~Redemption~~

accepted, and substantially all the exchanges settled on March 25, 2019. In ~~June 2018, ETP~~connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes:

•$~~500~~1.14 billion aggregate principal amount of 7.50% senior notes due 2020;

•$995 million aggregate principal amount of ~~4.20%~~4.25% senior notes due 2023;

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•$~~1.00~~1.13 billion aggregate principal amount of ~~4.95%~~5.875% senior notes due ~~2028;~~2024; and

•$~~500~~956 million aggregate principal amount of ~~5.80%~~5.50% senior notes due ~~2038; and~~2027.

•~~$1.00 billion aggregate principal amount of 6.00% senior notes due 2048.~~

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.

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The senior notes rank equally in right of payment with ~~ETP’s~~ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ~~ETP~~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.

The ~~$2.96~~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 ~~borrowings outstanding under ETP’s revolving credit facility,~~its term loan in full), for general partnership purposes and to redeem at maturity all of the ~~following senior notes:~~following:

•~~ETP’s $650 million aggregate principal amount of 2.50% senior notes due June 15, 2018;~~

•~~Panhandle’s~~ETO’s $400 million aggregate principal amount of ~~7.00%~~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 ~~15, 2018;~~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:

•~~ETP’s~~$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

In March 2019, Sunoco LP issued $600 million aggregate principal amount of ~~6.70%~~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 ~~1, 2018.~~

~~The aggregate amount paid to redeem~~2019, Sunoco LP completed an exchange of these notes ~~was approximately $1.65 billion.~~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

~~ETP~~ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement providing 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 and for general partnership purposes. The term loan agreement will be unsecured 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 assigned to the senior, unsecured, non-credit enhanced long-term debt of ETO.

ETO Five-Year Credit Facility

~~ETP’s~~ETO’s revolving credit facility (the ~~“ETP~~“ETO Five-Year Credit Facility”) ~~previously allowed~~allows for unsecured borrowings up to ~~$4.00 billion and matured in December 2022. On October 19, 2018, the ETP Five-Year Credit Facility was amended to increase the borrowing capacity by $1.00 billion, to~~ $5.00 billion and ~~to extend the maturity date to~~matures on December 1, 2023. The ~~ETP~~ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.

As of September 30, ~~2018,~~2019, the ~~ETP~~ETO Five-Year Credit Facility had ~~$1.78~~$2.61 billion of outstanding borrowings, $2.15 billion of which ~~$1.57 billion~~ was commercial paper. The amount available for future borrowings was ~~$2.06~~$2.32 billion after taking into account letters of credit of ~~$163 million, but before taking into account the additional capacity from the October 19, 2018 amendment.~~$77 million. The weighted average interest rate on the total amount outstanding as of September 30, ~~2018~~2019 was ~~3.00%~~2.77%.

~~ETP~~ETO 364-Day Facility

~~ETP’s~~ETO’s 364-day revolving credit facility (the ~~“ETP~~“ETO 364-Day Facility”) ~~previously allowed~~allows for unsecured borrowings up to $1.00 billion and ~~matured~~matures on ~~November 30, 2018. On October 19, 2018, the ETP 364-Day Facility was amended to extend the maturity date to~~ November 29, 2019. As of September 30, ~~2018,~~2019, the ~~ETP~~ETO 364-Day Facility had no0 outstanding borrowings.

~~Bakken~~Sunoco LP Credit Facility

~~In August 2016, ETP and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50~~Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”), which matures in ~~August 2019 (the “Bakken Credit Facility”).~~July 2023. As of September 30, ~~2018,~~2019, the ~~Bakken~~Sunoco LP Credit Facility had ~~$2.50 billion~~$154 million of outstanding borrowings ~~all~~and $8 million in standby letters of ~~which has been reflected in current maturities~~credit. As of ~~long-term debt on~~September 30, 2019, Sunoco LP had $1.34 billion of availability under the ~~Partnership’s consolidated balance sheet.~~Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, ~~2018~~2019 was ~~3.85%~~4.04%.

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 30, 2019, the USAC Credit Facility had $395 million of outstanding borrowings and 0 outstanding letters of credit. As of September 30, 2019, USAC had $1.21 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $410 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.73%.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, ~~2018.~~2019.


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 30, 2019 included (i) $477 million related

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to the USAC Preferred Units described below and (ii) $22 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.

USAC Preferred Units

In 2018, USAC issued 500,000 USAC Preferred Units in a private placement at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million.

The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed.


8.	EQUITY

Subsequent to the Energy Transfer Merger in October 2018, 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 30, 2019 and December 31, 2018, our outstanding preferred units included 950,000 Series A Preferred Units, 550,000Series B Preferred Units, 18,000,000 Series C Preferred Units and 17,800,000 Series D Preferred Units. As of September 30, 2019, our outstanding preferred units also included 32,000,000 Series E Preferred Units.

The following table summarizes changes in ~~outstanding common~~the amounts of our Series A, Series B, Series C, Series D and Series E preferred units ~~during~~for the nine months ended September 30, ~~2018 were as follows:~~2019:



	~~Number of Units~~
~~Number of common units at December 31, 2017~~	~~1,164.1~~
~~Common units issued in connection with the distribution reinvestment plan~~	~~2.9~~
~~Common units issued in connection with certain transactions~~	~~1.3~~
~~Issuance of common units under equity incentive plans~~	~~0.1~~
~~Repurchases of common units in open-market transactions~~	~~(1.2~~	)
~~Number of common units at September 30, 2018~~	~~1,167.2~~



	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

~~Subsequent to~~

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The following table summarizes changes in the ~~ETE-ETP Merger in October 2018, all~~amounts of the outstanding ETP common units are held directly or indirectly by ETE, including the ETP common units issued in connection with the conversion of the general partner interest to a non-economic interest and the cancellation of the IDRs, as discussed in Note 1, and the contributions of the investments in ETE’s other subsidiaries, as discussed in Note 2. In addition, the ETP Class I units and Class J units were also cancelled in connection with the ETE-ETP Merger.

~~Equity Distribution Program~~

During the nine months ended September 30, 2018, there were no units issued under the Partnership’s equity distribution agreement. In connection with the ETE-ETP Merger, the equity distribution program was terminated in October 2018.

~~Distribution Reinvestment Program~~

During the nine months ended September 30, 2018, distributions of $57 million were reinvested under the Partnership’s distribution reinvestment plan. In connection with the ETE-ETP Merger, the distribution reinvestment program was terminated in October 2018.

~~Preferred Units~~

ETP issued 950,000 Series A Preferred Units and 550,000 Series B Preferred Units in November 2017 and has issued additional preferred units in 2018, as discussed below. Subsequent to the ETE-ETP Merger, all of ETP’sour Series A, Series B, Series C and Series D ~~Preferred Units remain outstanding.~~preferred units for the nine months ended September 30, 2018:



	Preferred Unitholders
	Series A			Series B			Series C			Series D			Total
Balance, December 31, 2017	$	944		$	547		$	—		$	—		$	1,491
Distributions to partners	(15		)	(9		)	—			—			(24		)
Other, net	(1		)	(1		)	—			—			(2		)
Net income	15			9			—			—			24
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
Distributions to partners	(29		)	(18		)	(10		)	—			(57		)
Units issued for cash	—			—			—			431			431
Other, net	—			—			(1		)	(1		)	(2		)
Net income	15			9			8			6			38
Balance, September 30, 2018	$	944		$	547		$	439		$	436		$	2,366

Series CE Preferred Units Issuance

In April ~~2018, ETP~~2019, ETO issued 1832 million of its ~~7.375%~~7.600% Series CE Preferred Units at a price of $25 per unit, ~~resulting in~~including 4 million Series E Preferred Units pursuant to the underwriters’ exercise 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 ~~$450 million.~~their option. The net proceeds were used to repay amounts outstanding under ~~ETP’s revolving credit facility~~ETO’s Five-Year Credit Facility and for general partnership purposes.

Distributions on the Series CE Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, ~~2023,~~2024, at a rate of ~~7.375%~~7.600% per annum of the stated liquidation preference of $25. On and after May 15, ~~2023,~~2024, distributions on the Series CE Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of ~~4.530%~~5.161% per annum. The Series CE Preferred Units are redeemable at ~~ETP’s~~ETO’s option on or after May 15, ~~2023~~2024 at a redemption price of $25 per Series ~~C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.~~

~~Series D Preferred Units Issuance~~

In July 2018, ETP issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $445 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.

Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.378% per annum. The Series D Preferred Units are redeemable at ETP’s option on or after August 15, 2023 at a redemption price of $25 per Series D

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

~~Cash Distributions~~Subsidiary Equity Transactions

~~Distributions on~~Sunoco LP Equity Distribution Program

For the nine months ended September 30, 2019, Sunoco LP issued 0 additional units under its at-the-market equity distribution program. As of September 30, 2019, $295 million of Sunoco LP common units ~~declared and paid~~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 ~~subsequent to December 31, 2017 but prior to~~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 ~~closing~~nine months ended September 30, 2019, distributions of $0.7 million were reinvested under the ~~ETE-ETP Merger as discussed~~USAC distribution reinvestment program resulting in ~~Note 1 were as follows:~~the issuance of approximately 44,605 USAC common units.

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Quarter Ended Record Date Payment Date Rate
December 31, 2017 February 8, 2018 February 14, 2018 $ 0.5650
March 31, 2018 May 7, 2018 May 15, 2018 0.5650
June 30, 2018 August 6, 2018 August 14, 2018 0.5650

Cash Distributions

Distributions on ~~ETP’s~~ETO’s preferred units declared and/or paid by the Partnership subsequent to December 31, ~~2017~~2018 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 Rate
Series A Preferred Units
December 31, 2017 February 1, 2018 February 15, 2018 $ 15.451
June 30, 2018 August 1, 2018 August 15, 2018 31.250
Series B Preferred Units
December 31, 2017 February 1, 2018 February 15, 2018 $ 16.378
June 30, 2018 August 1, 2018 August 15, 2018 33.125
Series C Preferred Units
June 30, 2018 August 1, 2018 August 15, 2018 $ 0.5634
September 30, 2018 November 1, 2018 November 15, 2018 0.4609
Series D Preferred Units
September 30, 2018 November 1, 2018 November 15, 2018 $ 0.5931
⁽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.

Sunoco LP Cash Distributions

Distributions declared and/or paid by Sunoco LP subsequent to December 31, 2018 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

USAC Cash Distributions

Distributions declared and/or paid by USAC subsequent to December 31, 2018 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

Accumulated Other Comprehensive Income (Loss)

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



	September 30, 2019			December 31, 2018
Available-for-sale securities	$	10		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(41		)	(48		)
Investments in unconsolidated affiliates, net	(4		)	9
Total AOCI, net of tax	$	(40	)	$	(42	)

September 30, 2018 December 31, 2017
Available-for-sale securities ⁽¹⁾
$ 6
$ 8
Foreign currency translation adjustment (5 ) (5 )
Actuarial loss related to pensions and other postretirement benefits (7 ) (5 )
Investments in unconsolidated affiliates, net 14
5
Total AOCI, net of tax $ 8
$ 3


⁽¹⁾	~~Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01,~~ ~~Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale securities to common unitholders.~~


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. For the three and nine months ended September 30, 2018, the Partnership’s income tax benefit also reflected $109 million and $179 million, respectively, of deferred benefit adjustments as the result of a state statutory rate reduction.

ETC Sunoco ~~Inc.~~ historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with ~~Sunoco, Inc.’s~~ETC Sunoco’s 2004 through 2011 years, ETC Sunoco ~~Inc.~~ filed amended returns with the Internal

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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 ~~Inc.~~ petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the CFC ruled against ETC Sunoco, ~~Inc.,~~ and the Federal Circuit affirmed the CFC’s ruling on November 1, 2018. ETC Sunoco ~~Inc. is considering seeking further~~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 ~~this decision.~~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~~$530 million was previously established for the full amount of the pending refund ~~claims.~~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

~~Guarantee~~FERC Proceedings

By order issued January 16, 2019, the FERC initiated a review of ~~Sunoco LP Notes~~

~~In connection with previous transactions whereby Retail Holdings contributed assets~~Panhandle’s existing rates pursuant to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to certain of Sunoco LP’s senior notes and $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignmentSection 5 of the ~~guarantee~~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 ~~Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).~~

~~On January 23, 2018, Sunoco LP redeemed~~ the ~~previously guaranteed senior notes, repaid~~Natural Gas Act. The Natural Gas Act Section 5 and ~~terminated~~Section 4 proceedings were consolidated by the ~~term loan and issued the following notes (the “Sunoco LP Notes”) for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:~~

~~$1.00 billion aggregate principal amount of 4.875% senior notes due 2023;~~

~~$800 million aggregate principal amount of 5.50% senior notes due 2026; and~~

~~$400 million aggregate principal amount of 5.875% senior notes due 2028.~~

~~Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including~~order dated October 1, 2019. A hearing in the ~~context~~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 ~~bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect~~Southwest Gas’ existing rates pursuant to ~~such payment obligation, and holders~~Section 5 of the ~~notes~~Natural Gas Act to determine whether the rates currently charged by Southwest Gas are ~~still owed amounts~~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 ~~respect~~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 ~~principal~~Natural Gas Act. On July 22, 2019, Sea Robin filed an Offer of ~~such notes. ETC M-A will~~Settlement in this Section 4 proceeding, which settlement was supported or not ~~otherwise be subject to the covenants of the indenture governing the notes.~~

In connection with the issuance of the Sunoco LP Notes, Sunoco LP entered into a registration rights agreement with the initial purchasers pursuant to which Sunoco LP agreed to complete an offer to exchange the Sunoco LP Notes for an issue of registered notes with terms substantively identical to each series of Sunoco LP Notesopposed by Commission Trial Staff and ~~evidencing the same indebtedness as the Sunoco LP Notes on or before January 23, 2019.~~

~~FERC Audit~~

~~In March 2016,~~all active parties. By order dated October 17, 2019, the FERC ~~commenced an audit of Trunkline for~~approved the ~~period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts~~settlement as ~~prescribed by the FERC,~~filed, and the FERC’s annual reporting requirements. The FERC approved an audit report in October 2018. In response to the findings in the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company doesthere is not ~~expect the findings to result in any changes to its financial statements.~~a material impact on revenue.

Commitments

In the normal course of business, ~~ETP~~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. ~~ETP~~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.

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We have certain non-cancelable ~~leases for property and equipment,~~rights-of-way (“ROW”) commitments, which require fixed ~~monthly rental~~ payments and either expire upon our chosen abandonment or at various dates ~~through 2034.~~in the future. The table below reflects ~~rental~~ROW expense ~~under these operating leases~~ included in operating expenses in the accompanying statements of ~~operations,~~operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
ROW expense	$	5	$	5	$	17	$	18

PES Refinery Fire and Bankruptcy

We own an approximately 7.4% non-operating interest in PES, which ~~include contingent rentals,~~owns a refinery in Philadelphia. In addition, the Partnership provides logistics services to PES under commercial contracts and ~~rental expense recovered~~Sunoco LP has historically 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") filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have 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 Partnership has not recorded a valuation allowance related to the note receivable as of September 30, 2019, because management is not yet able to determine the collectability of the note in bankruptcy.

In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of September 30, 2019, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such claims, 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; 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 ~~sublease rental income:~~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. 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.

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
Rental expense $ 21
$ 29
$ 60
$ 68

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 (“the Court”) against the USACE and challenged the legality of these permits and claimed violations of the National Historic Preservation Act (“NHPA”). ~~The~~ SRST also sought a preliminary injunction to rescind the USACE permits while the case was pending, which the ~~court~~Court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. ~~The~~ SRST filed an amended complaint and added claims based on treaties between ~~the~~ SRST and ~~the~~ CRST and the United States and statutes governing the use of government property.

In February 2017, in response to a ~~presidential~~Presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. ~~The~~ 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 ~~the~~ CRST.

~~The~~In June 2017, SRST and ~~the~~ CRST amended their complaints to incorporate religious freedom and other claims. In addition, 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 ~~the~~ SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.

On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court 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 Act (“NEPA”) 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. On May 3, 2018, the District 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 will conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they will 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. The USACE indicated that a document detailing its remand analysis would be filed after a “confidentiality review.” Following the submission by USACE of its detailed remand analysis, it is expected that the Court will make a determination regarding the three discrete issues covered by the remand order.

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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 compliance 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 has 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 has 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.

In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, 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 compliance 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 ~~District~~ 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 ~~February~~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 ~~docketed a motion by CRST~~that they would need until August 31, 2018 to ~~“compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re~~finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and ~~remand conditions.” The motions seek an order from~~that it had determined that the three issues remanded by the Court ~~directing~~had been correctly decided. On October 1, 2018, the USACE asproduced a detailed remand analysis document supporting that determination. The Tribes and certain of the individuals sought leave of the Court to ~~how it should conduct its additional review on remand. Dakota Access pipeline~~amend their complaints to challenge the remand process and the ~~USACE opposed both motions.~~ USACE’s decision on remand.

On ~~April 16, 2018,~~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 ~~both motions.~~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 scheduled to conclude by November 20, 2019.

While ~~ETP believes~~we believe that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. ~~ETP~~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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Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL ~~Mont Belvieu’s~~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. Lone Star is still quantifying the extent of its incurred and ongoing damages and has orobtained, and will ~~be seeking~~continue to seek, reimbursement for these losses.

MTBE Litigation

ETC Sunoco ~~Inc. and/or Sunoco, Inc. (R&M) (now known as~~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 30, ~~2018,~~2019, Sunoco ~~Inc.~~ is a defendant in ~~six~~5 cases, including one case each initiated by the States of Maryland ~~Vermont~~ 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 ~~Energy Transfer Partners, L.P.,~~ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P.

In late July 2018, the Court in the Vermont matter denied Plaintiff’s motion to amend its complaint to add specific allegations regarding some of the sites the court previously dismissed. In early September 2018, Sunoco, Inc. participated in a defense group effort to resolve the case without further litigation. A settlement in principle to resolve the remaining statewide Vermont Case was reached in September 2018. (“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,

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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-ETP~~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 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;~~LP, Regency GP ~~LLC; ETE, ETP,~~LLC, ET, ETO, ETP GP, and the members of Regency’s board of ~~directors (“Defendants”).~~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.~~faith or fair to Regency. On March 29, 2016, the Delaware Court of Chancery granted ~~Defendants’~~the defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. ~~Defendants~~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 in part and denying 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 Court of Chancery granted Dieckman’s unopposed motion for class certification. On May 14, 2019, the Regency Defendants filed 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 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 ~~September 23-27,~~December 10-16, 2019.

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.

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

On January 27, 2014, a trial commenced between ~~ETP~~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 ~~ETP~~ETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ~~ETP.~~ETO. The jury also found that ~~ETP~~ETO owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ~~ETP~~ETO and awarded ~~ETP~~ETO $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ~~ETP~~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. ~~ETP’s~~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. ~~ETP’s~~On June 28, 2019, the Texas Supreme Court granted ETO’s petition for review ~~remains under consideration by~~and oral argument was heard on October 8, 2019. The parties now await a decision.

Rover

On November 3, 2017, the ~~Texas Supreme Court.~~

~~ETE-ETP Merger Litigation~~

~~On September~~State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) 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 as defendants on April 17, 2018 ~~William D. Warner (“Plaintiff”), a purported ETP unitholder, filed a putative class action asserting violations of various provisions of the Securities Exchange Act of 1934~~ and various rules promulgated thereunder in connection with the ETE-ETP Merger against ETP, Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff specificallyJuly 18, 2018.

Ohio EPA alleges that the ~~Form S-4 Registration Statement issued~~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 ~~connection~~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 ~~ETE-ETP Merger omits and/or misrepresents material information. Defendants believe~~court granted Rover and the ~~allegations have no merit~~other Defendants’ motion to dismiss on all counts. On April 10, 2019, the Ohio EPA filed a notice of appeal. The Ohio EPA’s appeal is now pending before the Fifth District court of appeals. Briefing was completed in August of 2019 and ~~intend~~oral argument has been set for November 5, 2019.

In January 2018, Ohio EPA sent a letter to ~~defend vigorously against them. On October 26,~~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 ~~Plaintiff~~response to the FERC and ~~Defendants entered into a stipulation staying Defendants’ response deadlines until the designation of a lead plaintiff/lead counsel structure~~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 ~~Private Securities Litigation Reform Act.~~FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release 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.

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. ~~ETP,~~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.

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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 the preliminary injunction 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 merits of the appeal, that is, whether 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~~district court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the ~~District Court.~~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 ~~11,~~18, 2018. On September ~~11,~~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 ~~Plaintiff’s~~Plaintiffs’ original complaint, which it has done. ~~Summary~~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 ~~concluded by the Spring of 2019.~~

~~Rover~~

~~On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”)~~allowed to update any summary judgment briefs they have already filed, suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) 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 as 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,~~if necessary, 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 EPAcourt 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 ~~opposition.~~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.

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 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.

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

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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 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.

The Partnership continues to work through these issues with PADEP during the pendency of these appeals.

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 ~~January~~December 2018, ~~Ohio EPA~~the Chester County District Attorney sent a letter to the ~~FERC~~Partnership stating that it was investigating the Partnership and related entities for “potential crimes” related to ~~express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as~~the Mariner East pipelines.

Subsequently, the matter was submitted to an Investigating grand Jury in Chester County, Pennsylvania. As part of the ~~Rover Pipeline construction. Rover~~Grand Jury proceedings, since April and August 2019, the Partnership was served with a total of forty-one grand jury subpoenas seeking a variety of documents and records sought by the Chester County Investigation Grand Jury. On September 24, 2019, the Chester County District Attorney sent a ~~January 24 response~~Notice of Intent to the ~~FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting~~Partnership of its ~~drilling operations in accordance with specified procedures that had been approved by~~intent to pursue an abatement action if certain conditions were not remediated. The Partnership intends to respond to the ~~FERC and reviewed by~~notice of Intent within the ~~Ohio EPA. In addition, although~~proscribed time period.

Delaware County, Pennsylvania Investigation

On March 11, 2019, the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concernDelaware County District Attorney’s Office (“Delaware County D.A.”) announced that the ~~drilling fluids could deprive organisms~~Delaware County D.A. and the Pennsylvania Attorney General’s Office, at the request of the Delaware County D.A., 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 the ~~wetland of oxygen. Rover, however, has now fully remediated~~specific conduct under investigation. This investigation is ongoing. While the ~~site, a fact~~Partnership will cooperate with ~~which Ohio EPA concurs.~~the investigation, it intends to vigorously defend itself against these allegations.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, ~~2018~~2019 and December 31, ~~2017,~~2018, accruals of approximately ~~$55~~$61 million and $53 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.

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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 as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against ~~Sunoco Pipeline L.P. (“SPLP”)~~SPLP before the ~~Pennsylvania Public Utility Commission (“PUC”).~~PUC. Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” 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’s

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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 ~~2018~~ 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 ~~Pennsylvania Department of Environmental Protection (“PADEP”)~~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 ~~the action.~~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 ~~27, 2018,~~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 ~~that certified for~~remanded the case to the PUC to dissolve the interim emergency injunction and dismiss the Complaint. Senator Dinniman has not sought to appeal the ~~issue~~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’s standing. The Order stays~~Dinniman filed a letter objecting to SPLP’s request, arguing the Commonwealth Court’s order staying all proceedings inbarred the ~~PUC.~~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.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the PADEP. The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting. On August 7, 2017 a final settlement was reached. A stipulated order has been submitted to the EHB Judge with respect to the settlement. The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project. The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation. Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits. Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company. On July 31, 2018 the underlying permit appeals in which the above settlements occurred were withdrawn in a settlement between the appellants and PADEP. That settlement did not involve SPLP.

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In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project. Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval. SPLP has fulfilled the requirements of those agreements and has been authorized by PADEP to resume drilling the locations.

NoNaN amounts have been recorded in our September 30, ~~2018~~2019 or December 31, ~~2017~~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 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”) ~~operated and owned by SPLP~~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) ~~operated by SPLP and owned by Mid-Valley~~which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma ~~operated and owned by SPLP~~which allegedly occurred in January 2015. In ~~July 2017, we had~~January 2019, a ~~meeting with~~Consent Decree approved by all parties as well as an accompanying Complaint was filed in the ~~DOJ, EPA~~United States District Court for the Western District of Louisiana seeking public comment and Louisiana Department of Environmental Quality (“LDEQ”) during which the agencies presented their initial demand for civil penalties and injunctive relief. Since then, the parties have reached an agreement in principalfinal court approval to resolve all penalties with DOJ and LDEQ ~~along with~~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 ~~requirements~~ to be completed on the Longview-to-Mayersville pipeline within three years ~~all of which~~but the injunctive relief is ~~being formalized in a Consent Decree.~~not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss ~~national~~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 Order 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.

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

On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The 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.

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Environmental Remediation

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


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

~~certain~~

Table 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 responsible for contamination caused by other parties.Contents

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


•	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 30, 2019, ETC Sunoco had been named as a PRP at approximately 38 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.

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

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2018, Sunoco, Inc. had been named as a PRP at approximately 41 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’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
Current	$	46	$	42
Non-current	276		295
Total environmental liabilities	$	322	$	337

September 30, 2018 December 31, 2017
Current $ 36
$ 36
Non-current 281
314
Total environmental liabilities $ 317
$ 350

~~In 2013, we~~We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the three months ended September 30, ~~2018~~2019 and ~~2017,~~2018, the Partnership recorded ~~$17~~$16 million and $5$17 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, ~~2018~~2019 and ~~2017,~~2018, the Partnership recorded ~~$28~~$31 million and ~~$18~~$32 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 ~~Pipeline Hazardous Materials Safety Administration (“PHMSA”),~~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 ~~Health~~Safety and ~~Safety~~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

The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 1. These policies were applied to the current period only, and the amounts reflected in the Partnership’s consolidated financial statements for the three and nine months ended September 30, 2017 were recorded under the Partnership’s previous accounting policies.

Disaggregation of ~~revenue~~Revenue

The Partnership’s consolidated financial statements reflect ~~the following six~~eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure ~~purposes:~~

~~intrastate transportation and storage;~~

~~interstate transportation and storage;~~

~~midstream;~~

~~NGL and refined products transportation and services;~~

~~crude oil transportation and services; and~~

~~all other.~~

purposes. Note 1415 depicts the disaggregation of revenue by ~~segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.~~

~~Intrastate transportation and storage revenue~~

Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

~~Interstate transportation and storage revenue~~

Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible.

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Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

~~Midstream revenue~~

Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include:

~~Fixed fee gathering and processing:~~ ~~Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed.~~

~~Keepwhole:~~ Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed.

~~Percent of Proceeds (“POP”):~~ Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:

~~In-Kind POP:~~ We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.

~~Mixed POP:~~ We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received.

~~Payment for services under these contracts are typically due the month after the services have been performed.~~

The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer,

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deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for 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.

~~NGL and refined products transportation and services revenue~~

Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.

~~Crude oil transportation and services revenue~~

Our crude oil transportation and service segment are primarily derived from provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed.

Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.

The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

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~~Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606.~~

~~All other revenue~~

Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard.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. ~~As of September 30, 2018 and January 1, 2018, no contract assets have been recognized.~~

The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allows 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. AsAdditionally, 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, 2018	$	392
Additions	448
Revenue recognized	(491		)
Balance, September 30, 2019	$	349

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

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. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis.

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



	September 30, 2019		December 31, 2018
Contract asset balances:
Contract asset	$	102	$	75
Accounts receivable from contracts with customers	403		348

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Costs to Obtain or Fulfill a Contract

Sunoco LP recognizes an asset from the ~~Partnership had $349 million~~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 ~~deferred revenues representing~~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 ~~value~~assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of ~~our future performance obligations.~~

transfer of the goods or services to which such costs relate. The amount of ~~revenue~~amortization expense that Sunoco LP recognized for the three months ended September 30, 2019 and 2018 was $4 million and $4 million, respectively. The amount of amortization expense that Sunoco LP recognized for the nine months ended September 30, ~~2018 that was included in the deferred revenue liability balance as of January 1,~~2019 and 2018 was $12 million and ~~$75~~$10 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 ~~it expects to be entitled to,~~ to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contacts, only the fixed component of the contracts are included in the table below.

As of September 30, ~~2018,~~2019, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is ~~$40.13~~$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

Years Ending December 31,
2018 (remainder) 2019 2020 Thereafter Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2018 $ 1,426
$ 5,066
$ 4,568
$ 29,069
$ 40,129

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~~Practical Expedients Utilized by the Partnership~~

~~The Partnership elected the following practical expedients in accordance with Topic 606:~~

~~Right to invoice:~~ The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers.

~~Significant financing component:~~ The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

~~Unearned variable consideration:~~ The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components.


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 onin 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 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
	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
Fixed Swaps/Futures	1,723		2019-2020	468		2019
Options – Puts	—		—	10,000		2019
Power (Megawatt):
Forwards	2,847,350		2019-2029	3,141,520		2019
Futures	222,440		2019-2020	56,656		2019-2021
Options – Puts	515,317		2019-2020	18,400		2019
Options – Calls	(756,153	)	2019-2021	284,800		2019
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(23,653	)	2019-2022	(30,228	)	2019-2021
Swing Swaps IFERC	22,365		2019-2020	54,158		2019-2020
Fixed Swaps/Futures	2,323		2019-2021	(1,068	)	2019-2021
Forward Physical Contracts	(29,492	)	2019-2021	(123,254	)	2019-2020
NGLs (MBbls) – Forwards/Swaps	(9,687	)	2019-2021	(2,135	)	2019
Refined Products (MBbls) – Futures	(906	)	2019-2021	(1,403	)	2019
Crude (MBbls) – Forwards/Swaps	9,510		2019-2020	20,888		2019
Corn (thousand bushels)	(1,760	)	2019	(1,920	)	2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(31,703	)	2019-2020	(17,445	)	2019
Fixed Swaps/Futures	(31,703	)	2019-2020	(17,445	)	2019
Hedged Item – Inventory	31,703		2019-2020	17,445		2019

September 30, 2018 December 31, 2017
Notional Volume Maturity Notional Volume Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures 358
2018-2019 1,078
2018
Basis Swaps IFERC/NYMEX ⁽¹⁾
69,685
2018-2020 48,510
2018-2020
Options – Puts (17,273 ) 2019 13,000
2018
Power (Megawatt):
Forwards 429,720
2018-2019 435,960
2018-2019
Futures 309,123
2018-2019 (25,760 ) 2018
Options – Puts 157,435
2018-2019 (153,600 ) 2018
Options – Calls 321,240
2018-2019 137,600
2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX (7,705 ) 2018-2021 4,650
2018-2020
Swing Swaps IFERC 69,145
2018-2019 87,253
2018-2019
Fixed Swaps/Futures (1,784 ) 2018-2020 (4,700 ) 2018-2019
Forward Physical Contracts (54,151 ) 2018-2020 (145,105 ) 2018-2020
NGL (MBbls) – Forwards/Swaps (4,997 ) 2018-2019 (2,493 ) 2018-2019
Crude (MBbls) – Forwards/Swaps 35,280
2018-2019 9,172
2018-2019
Refined Products (MBbls) – Futures (1,521 ) 2018-2019 (3,783 ) 2018-2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX (21,475 ) 2018-2019 (39,770 ) 2018
Fixed Swaps/Futures (21,475 ) 2018-2019 (39,770 ) 2018
Hedged Item – Inventory 21,475
2018-2019 39,770
2018


⁽¹⁾	Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

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The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	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
September 30, 2018 December 31, 2017
July 2018⁽²⁾
Forward-starting to pay a fixed rate of 3.76% and receive a floating rate $ —
$ 300
July 2019⁽²⁾
Forward-starting to pay a fixed rate of 3.56% and receive a floating rate 400
300
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
—
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
300


⁽¹⁾	Floating rates are based on 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.

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 ~~industrials,~~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
	Asset Derivatives				Liability Derivatives
	September 30, 2019		December 31, 2018		September 30, 2019			December 31, 2018
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	16	$	—	$	—		$	(13	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	543		402		(520		)	(397		)
Commodity derivatives	120		158		(77		)	(173		)
Interest rate derivatives	—		—		(528		)	(163		)
	663		560		(1,125		)	(733		)
Total derivatives	$	679	$	560	$	(1,125	)	$	(746	)

Fair Value of Derivative Instruments
Asset Derivatives Liability Derivatives
September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits) $ —
$ 14
$ (6 ) $ (2 )
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits) 477
262
(537 ) (281 )
Commodity derivatives 122
44
(327 ) (55 )
Interest rate derivatives —
—
(97 ) (219 )
599
306
(961 ) (555 )
Total derivatives $ 599
$ 320
$ (967 ) $ (557 )

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
	Balance Sheet Location	September 30, 2019			December 31, 2018			September 30, 2019			December 31, 2018
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(528	)	$	(163	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	120			158			(77		)	(173		)
Broker cleared derivative contracts	Other current assets (liabilities)	559			402			(520		)	(410		)
Total gross derivatives		679			560			(1,125		)	(746		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(64		)	(47		)	64			47
Counterparty netting	Other current assets (liabilities)	(519		)	(397		)	519			397
Total net derivatives		$	96		$	116		$	(542	)	$	(302	)

Asset Derivatives Liability Derivatives
Balance Sheet Location September 30, 2018 December 31, 2017 September 30, 2018 December 31, 2017
Derivatives without offsetting agreements Derivative liabilities $ —
$ —
$ (97 ) $ (219 )
Derivatives in offsetting agreements:
OTC contracts Derivative assets (liabilities) 122
44
(327 ) (55 )
Broker cleared derivative contracts Other current assets (liabilities) 477
276
(543 ) (283 )
Total gross derivatives 599
320
(967 ) (557 )
Offsetting agreements:
Counterparty netting Derivative assets (liabilities) (29 ) (20 ) 29
20
Counterparty netting Other current assets (liabilities) (477 ) (263 ) 477
263
Total net derivatives $ 93
$ 37
$ (461 ) $ (274 )

We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or ~~long-term~~non-current depending on the anticipated settlement date.

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The following tables summarize the amounts recognized in income 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 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,
2018 2017 2018 2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives Cost of products sold $ —
$ 2
$ 9
$ 4



	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2019			2018		2019			2018
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3		$	3	$	15		$	36
Commodity derivatives – Non-trading	Cost of products sold	21			21		(53		)	(345		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(175		)	45		(371		)	117
Total		$	(151	)	$	69	$	(409	)	$	(192	)

Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain/(Loss) Recognized in Income on Derivatives
Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading Cost of products sold $ 3
$ (5 ) $ 36
$ 21
Commodity derivatives – Non-trading Cost of products sold 21
(12 ) (352 ) (15 )
Interest rate derivatives Gains (losses) on interest rate derivatives 45
(8 ) 117
(28 )
Embedded derivatives Other, net —
—
—
1
Total $ 69
$ (25 ) $ (199 ) $ (21 )


~~13.~~14.	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 30, 2019 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 promissory note due 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.

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

As of September 30, 2019, ETO has a long-term intercompany payable due to ET of $85 million, which has been netted against the outstanding promissory notes receivable in our consolidated balance sheet.

The Partnership also has related party transactions with several of its ~~equity method investees.~~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 ~~affiliate~~ 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
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
Affiliated revenues $ 192
$ 190
$ 700
$ 441

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



	September 30, 2019		December 31, 2018
Accounts receivable from related companies:
ET	$	71	$	65
FGT	51		25
Phillips 66	36		42
Traverse	25		—
Other	41		44
Total accounts receivable from related companies	$	224	$	176

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

September 30, 2018 December 31, 2017
Accounts receivable from related companies:
ETE $ 42
$ —
FGT 15
11
Phillips 66 30
20
Sunoco LP 207
219
Trans-Pecos Pipeline, LLC 10
1
Other 29
67
Total accounts receivable from related companies: $ 333
$ 318

Accounts payable to related companies:
Sunoco LP $ 178
$ 195
USAC 45
—
Other 64
14
Total accounts payable to related companies: $ 287
$ 209

September 30, 2018 December 31, 2017
Long-term notes receivable from related company:
Sunoco LP $ 85
$ 85


~~14.~~15.	REPORTABLE SEGMENTS

~~Our consolidated financial statements~~As a result of the Energy Transfer Merger in October 2018, our reportable segments were reevaluated and currently reflect the following ~~reportable~~ segments, which conduct their business primarily in the United ~~States, as follows:~~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 ~~amounts included~~investment in USAC segment reflects the ~~NGL and refined products transportation and services segment and~~results of USAC beginning April 2018, the ~~crude oil transportation and services segment have been retrospectively adjusted in these consolidated financial statements as a result~~date that the Partnership obtained control of ~~the Sunoco Logistics Merger.~~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 ~~refined product 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

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

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~~unrealized gains and losses on commodity derivatives and inventory fair value adjustments.~~ Segment Adjusted EBITDA ~~reflects~~and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the ~~Partnership's proportionate ownership.~~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,
	2019			2018			2019			2018
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	675		$	846		$	2,115		$	2,424
Intersegment revenues	89			76			270			186
	764			922			2,385			2,610
Interstate transportation and storage:
Revenues from external customers	475			440			1,454			1,174
Intersegment revenues	4			5			16			13
	479			445			1,470			1,187
Midstream:
Revenues from external customers	704			537			1,704			1,571
Intersegment revenues	876			1,716			2,792			4,170
	1,580			2,253			4,496			5,741
NGL and refined products transportation and services:
Revenues from external customers	2,271			2,845			7,340			7,467
Intersegment revenues	607			218			1,181			710
	2,878			3,063			8,521			8,177
Crude oil transportation and services:
Revenues from external customers	4,453			4,422			13,685			12,942
Intersegment revenues	—			16			—			44
	4,453			4,438			13,685			12,986
Investment in Sunoco LP:
Revenues from external customers	4,328			4,760			12,494			13,114
Intersegment revenues	3			1			4			3
	4,331			4,761			12,498			13,117
Investment in USAC:
Revenues from external customers	169			166			505			331
Intersegment revenues	6			3			15			5
	175			169			520			336
All other:
Revenues from external customers	420			498			1,196			1,491
Intersegment revenues	21			27			80			108
	441			525			1,276			1,599
Eliminations	(1,606		)	(2,062		)	(4,358		)	(5,239		)
Total revenues	$	13,495		$	14,514		$	40,493		$	40,514

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers $ 846
$ 729
$ 2,424
$ 2,196
Intersegment revenues 76
44
186
146
922
773
2,610
2,342
Interstate transportation and storage:
Revenues from external customers 390
220
1,026
652
Intersegment revenues 5
4
13
14
395
224
1,039
666
Midstream:
Revenues from external customers 537
665
1,571
1,863
Intersegment revenues 1,716
1,100
4,170
3,154
2,253
1,765
5,741
5,017
NGL and refined products transportation and services:
Revenues from external customers 2,948
1,989
7,878
5,874
Intersegment revenues 115
81
299
241
3,063
2,070
8,177
6,115
Crude oil transportation and services:
Revenues from external customers 4,422
2,714
12,942
7,749
Intersegment revenues 16
11
44
16
4,438
2,725
12,986
7,765
All other:
Revenues from external customers 498
656
1,490
2,110
Intersegment revenues 27
27
108
139
525
683
1,598
2,249
Eliminations (1,955 ) (1,267 ) (4,820 ) (3,710 )
Total revenues $ 9,641
$ 6,973
$ 27,331
$ 20,444

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	235		$	221		$	777		$	621
Interstate transportation and storage	442			459			1,358			1,200
Midstream	411			434			1,205			1,225
NGL and refined products transportation and services	667			498			1,923			1,410
Crude oil transportation and services	700			682			2,257			1,694
Investment in Sunoco LP	192			208			497			457
Investment in USAC	104			90			310			185
All other	37			(6		)	83			69
Total	2,788			2,586			8,410			6,861
Depreciation, depletion and amortization	(782		)	(747		)	(2,334		)	(2,100		)
Interest expense, net of capitalized interest	(575		)	(446		)	(1,680		)	(1,246		)
Impairment losses	(12		)	—			(62		)	—
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Non-cash compensation expense	(27		)	(27		)	(85		)	(82		)
Unrealized gains (losses) on commodity risk management activities	64			97			90			(255		)
Losses on extinguishments of debt	—			—			(2		)	(109		)
Inventory valuation adjustments	(26		)	(7		)	71			50
Adjusted EBITDA related to unconsolidated affiliates	(161		)	(179		)	(470		)	(503		)
Equity in earnings of unconsolidated affiliates	82			87			224			258
Adjusted EBITDA related to discontinued operations	—			—			—			25
Other, net	103			32			211			58
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

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017* 2018 2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage $ 221
$ 163
$ 621
$ 480
Interstate transportation and storage 416
273
1,069
800
Midstream 434
356
1,225
1,088
NGL and refined products transportation and services 498
439
1,410
1,208
Crude oil transportation and services 682
420
1,694
835
All other 78
133
242
363
Total 2,329
1,784
6,261
4,774
Depreciation, depletion and amortization (636 ) (596 ) (1,827 ) (1,713 )
Interest expense, net (387 ) (352 ) (1,091 ) (1,020 )
Gain on Sunoco LP common unit repurchase —
—
172
—
Loss on deconsolidation of CDM —
—
(86 ) —
Gains (losses) on interest rate derivatives 45
(8 ) 117
(28 )
Non-cash compensation expense (20 ) (19 ) (61 ) (57 )
Unrealized gains (losses) on commodity risk management activities 97
(81 ) (255 ) 17
Adjusted EBITDA related to unconsolidated affiliates (257 ) (279 ) (670 ) (765 )
Equity in earnings of unconsolidated affiliates 113
127
147
139
Other, net 13
27
100
79
Income before income tax (expense) benefit $ 1,297
$ 603

$ 2,807

$ 1,426

* As adjusted. See Note 1.

September 30, 2018 December 31, 2017
Assets:
Intrastate transportation and storage $ 5,874
$ 5,020
Interstate transportation and storage 14,143
13,518
Midstream 20,175
20,004
NGL and refined products transportation and services 18,438
17,600
Crude oil transportation and services 17,458
17,736
All other 3,068
4,087
Total assets $ 79,156
$ 77,965


~~15.~~16.	CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

Sunoco Logistics Partners Operations L.P., a subsidiary of ~~ETP,~~ETO, is the issuer of multiple series of senior notes that are guaranteed by ~~ETP.~~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.

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


	September 30, 2018													September 30, 2019
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership		Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	—		$	379	$	—		$	379	$	—	$	—	$	207	$	—		$	207
Accounts receivable, related parties														4,467		43,654		73,807		(121,704		)	224
All other current assets	4			56			6,806		(892		)	5,974		—		—		6,724		—			6,724
Property, plant and equipment, net	—			—			60,550		—			60,550		—		—		68,870		—			68,870
Investments in unconsolidated affiliates	49,614			12,435			3,599		(62,049		)	3,599		56,270		14,838		3,065		(71,186		)	2,987
All other assets	8			75			8,571		—			8,654		3,560		131		12,544		—			16,235
Total assets	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156	$	64,297	$	58,623	$	165,217	$	(192,890	)	$	95,247

Current liabilities	$	(1,118	)	$	(3,407	)	$	14,675	$	(892	)	$	9,258
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	22,823			7,605			4,794		—			35,222		31,260		7,603		13,751		—			52,614
Noncontrolling interest	—			—			6,334		—			6,334
Noncontrolling interests														—		—		7,974		—			7,974
Total partners’ capital	27,921			8,368			54,102		(62,049		)	28,342		29,658		10,368		60,411		(72,800		)	27,637
Total liabilities and equity	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156	$	64,297	$	58,623	$	165,217	$	(192,890	)	$	95,247


	December 31, 2017													December 31, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership		Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	(3	)	$	309	$	—		$	306	$	—	$	—	$	418	$	—		$	418
Accounts receivable, related parties														4,070		36,889		67,110		(107,893		)	176
All other current assets	—			159			6,063		—			6,222		—		—		6,226		—			6,226
Property, plant and equipment, net	—			—			58,437		—			58,437		—		—		66,655		—			66,655
Investments in unconsolidated affiliates	48,378			11,648			3,816		(60,026		)	3,816		51,876		13,090		2,636		(64,966		)	2,636
All other assets	—			—			9,184		—			9,184		12		75		12,244		—			12,331
Total assets	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965	$	55,958	$	50,054	$	155,289	$	(172,859	)	$	88,442

Current liabilities	$	(1,496	)	$	(3,660	)	$	12,150	$	—		$	6,994
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	21,604			7,607			7,609		—			36,820		24,787		7,605		10,132		—			42,524
Noncontrolling interest	—			—			5,882		—			5,882
Noncontrolling interests														—		—		7,903		—			7,903
Total partners’ capital	28,270			7,857			52,168		(60,026		)	28,269		27,741		8,932		56,523		(64,478		)	28,718
Total liabilities and equity	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965	$	55,958	$	50,054	$	155,289	$	(172,859	)	$	88,442

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	Three Months Ended September 30, 2018															Three Months Ended September 30, 2019
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership			Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	9,641		$	—		$	9,641		$	—		$	—		$	13,495		$	—		$	13,495
Operating costs, expenses, and other	—			—			8,136			—			8,136			—			—			11,661			—			11,661
Operating income	—			—			1,505			—			1,505			—			—			1,834			—			1,834
Interest expense, net	(303		)	(55		)	(29		)	—			(387		)
Interest expense, net of capitalized interest																(412		)	(151		)	(12		)	—			(575		)
Equity in earnings of unconsolidated affiliates	1,394			501			113			(1,895		)	113			1,443			519			82			(1,962		)	82
Gains on interest rate derivatives	45			—			—			—			45			(175		)	—			—			—			(175		)
Other, net	—			—			21			—			21			93			3			17			—			113
Income before income tax benefit	1,136			446			1,610			(1,895		)	1,297
Income tax benefit	—			—			(61		)	—			(61		)
Income before income tax expense																949			371			1,921			(1,962		)	1,279
Income tax expense																—			—			55			—			55
Net income	1,136			446			1,671			(1,895		)	1,358			949			371			1,866			(1,962		)	1,224
Less: Net income attributable to noncontrolling interest	—			—			223			—			223
Less: Net income attributable to noncontrolling interests																—			—			261			—			261
Less: Net income attributable to redeemable noncontrolling interests																—			—			12			—			12
Net income attributable to partners	$	1,136		$	446		$	1,448		$	(1,895	)	$	1,135		$	949		$	371		$	1,593		$	(1,962	)	$	951

Other comprehensive income	$	—		$	—		$	4		$	—		$	4
Other comprehensive loss																$	—		$	—		$	(7	)	$	—		$	(7	)
Comprehensive income	1,136			446			1,675			(1,895		)	1,362			949			371			1,859			(1,962		)	1,217
Comprehensive income attributable to noncontrolling interest	—			—			223			—			223
Less: Comprehensive income attributable to noncontrolling interests																—			—			261			—			261
Less: Comprehensive income attributable to redeemable noncontrolling interests																—			—			12			—			12
Comprehensive income attributable to partners	$	1,136		$	446		$	1,452		$	(1,895	)	$	1,139		$	949		$	371		$	1,586		$	(1,962	)	$	944

Table of Contents


	Three Months Ended September 30, 2017*														Three Months Ended September 30, 2018
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership			Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,973		$	—		$	6,973		$	—		$	—		$	14,514		$	—		$	14,514
Operating costs, expenses, and other	—		—			6,194			—			6,194			—			—			12,799			—			12,799
Operating income	—		—			779			—			779			—			—			1,715			—			1,715
Interest expense, net	—		(32		)	(320		)	—			(352		)
Interest expense, net of capitalized interest															(303		)	(55		)	(88		)	—			(446		)
Equity in earnings of unconsolidated affiliates	647		236			127			(883		)	127			1,394			501			87			(1,895		)	87
Losses on interest rate derivatives	—		—			(8		)	—			(8		)
Gains on interest rate derivatives															45			—			—			—			45
Other, net	—		1			56			—			57			—			—			40			—			40
Income before income tax benefit	647		205			634			(883		)	603
Income tax benefit	—		—			(112		)	—			(112		)
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	647		205			746			(883		)	715			1,136			446			1,804			(1,895		)	1,491
Less: Net income attributable to noncontrolling interest	—		—			110			—			110
Less: Net income attributable to noncontrolling interests															—			—			223			—			223
Less: Net income attributable to predecessor equity															—			—			133			—			133
Net income attributable to partners	$	647	$	205		$	636		$	(883	)	$	605		$	1,136		$	446		$	1,448		$	(1,895	)	$	1,135

Other comprehensive income	$	—	$	—		$	7		$	—		$	7		$	—		$	—		$	4		$	—		$	4
Comprehensive income	647		205			753			(883		)	722			1,136			446			1,808			(1,895		)	1,495
Comprehensive income attributable to noncontrolling interest	—		—			110			—			110
Less: Comprehensive income attributable to noncontrolling interests															—			—			223			—			223
Less: Comprehensive income attributable to predecessor equity															—			—			133			—			133
Comprehensive income attributable to partners	$	647	$	205		$	643		$	(883	)	$	612		$	1,136		$	446		$	1,452		$	(1,895	)	$	1,139

* As adjusted. See Note 1.

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	Nine Months Ended September 30, 2018															Nine Months Ended September 30, 2019
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership			Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	27,331		$	—		$	27,331		$	—		$	—		$	40,493		$	—		$	40,493
Operating costs, expenses, and other	—			—			23,910			—			23,910			—			—			34,904			—			34,904
Operating income	—			—			3,421			—			3,421			—			—			5,589			—			5,589
Interest expense, net	(870		)	(137		)	(84		)	—			(1,091		)
Interest expense, net of capitalized interest																(1,190		)	(280		)	(210		)	—			(1,680		)
Equity in earnings of unconsolidated affiliates	3,036			827			147			(3,863		)	147			4,292			1,638			224			(5,930		)	224
Gain on Sunoco LP unit repurchase	—			—			172			—			172
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Losses on extinguishments of debt																—			—			(2		)	—			(2		)
Gains on interest rate derivatives	117			—			—			—			117			(371		)	—			—			—			(371		)
Other, net	—			—			127			—			127			233			3			6			—			242
Income before income tax benefit	2,283			690			3,697			(3,863		)	2,807			2,964			1,361			5,607			(5,930		)	4,002
Income tax benefit	—			—			(32		)	—			(32		)
Income tax expense																—			—			216			—			216
Net income	2,283			690			3,729			(3,863		)	2,839			2,964			1,361			5,391			(5,930		)	3,786
Less: Net income attributable to noncontrolling interest	—			—			557			—			557
Less: Net income attributable to noncontrolling interests																—			—			783			—			783
Less: Net income attributable to redeemable noncontrolling interests																—			—			38			—			38
Net income attributable to partners	$	2,283		$	690		$	3,172		$	(3,863	)	$	2,282		$	2,964		$	1,361		$	4,570		$	(5,930	)	$	2,965

Other comprehensive income	$	—		$	—		$	7		$	—		$	7		$	—		$	—		$	2		$	—		$	2
Comprehensive income	2,283			690			3,736			(3,863		)	2,846			2,964			1,361			5,393			(5,930		)	3,788
Comprehensive income attributable to noncontrolling interest	—			—			557			—			557
Less: Comprehensive income attributable to noncontrolling interests																—			—			783			—			783
Less: Comprehensive income attributable to redeemable noncontrolling interests																						38						38
Comprehensive income attributable to partners	$	2,283		$	690		$	3,179		$	(3,863	)	$	2,289		$	2,964		$	1,361		$	4,572		$	(5,930	)	$	2,967

Table of Contents

Nine Months Ended September 30, 2017*
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues $ —
$ —
$ 20,444
$ —
$ 20,444
Operating costs, expenses, and other —
1
18,245
—
18,246
Operating income (loss) —
(1 ) 2,199
—
2,198
Interest expense, net —
(113 ) (907 ) —
(1,020 )
Equity in earnings of unconsolidated affiliates 1,657
1,001
139
(2,658 ) 139
Losses on interest rate derivatives —
—
(28 ) —
(28 )
Other, net —
4
134
(1 ) 137
Income before income tax expense 1,657
891
1,537
(2,659 ) 1,426
Income tax expense —
—
22
—
22
Net income 1,657
891
1,515
(2,659 ) 1,404
Less: Net income attributable to noncontrolling interest —
—
266
—
266
Net income attributable to partners $ 1,657
$ 891
$ 1,249
$ (2,659 ) $ 1,138

Other comprehensive income $ —
$ —
$ 6
$ —
$ 6
Comprehensive income 1,657
891
1,521
(2,659 ) 1,410
Comprehensive income attributable to noncontrolling interest —
—
266
—
266
Comprehensive income attributable to partners $ 1,657
$ 891
$ 1,255
$ (2,659 ) $ 1,144

* As adjusted. See Note 1.



	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

Nine Months Ended September 30, 2018
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows provided by operating activities $ 2,753
$ 582
$ 3,843
$ (2,078 ) $ 5,100
Cash flows used in investing activities (834 ) (579 ) (3,732 ) 2,078
(3,067 )
Cash flows used in financing activities (1,919 ) —
(41 ) —
(1,960 )
Change in cash —
3
70
—
73
Cash at beginning of period —
(3 ) 309
—
306
Cash at end of period $ —
$ —
$ 379
$ —
$ 379

Nine Months Ended September 30, 2017
Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows provided by operating activities $ 1,657
$ 802
$ 3,538
$ (2,660 ) $ 3,337
Cash flows used in investing activities (1,348 ) (1,127 ) (4,872 ) 2,660
(4,687 )
Cash flows provided by (used in) financing activities (309 ) 333
1,345
—
1,369
Change in cash —
8
11
—
19
Cash at beginning of period —
41
319
—
360
Cash at end of period $ —
$ 49
$ 330
$ —
$ 379

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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 filed with the SEC on February ~~23, 2018.~~22, 2019. 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, ~~2017~~2018 filed with the SEC on February ~~23, 2018.~~22, 2019.

References to “we,” “us,” “our,” the “Partnership” and ~~“ETP”~~“ETO” shall mean Energy Transfer Operating, L.P. ~~(formerly Energy Transfer Partners, L.P.)~~ and its subsidiaries.

~~OVERVIEW~~RECENT DEVELOPMENTS

ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement providing 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 and for general partnership purposes. The ~~primary activities~~term loan agreement will be unsecured and ~~operating subsidiaries through which we conduct those activities~~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 ~~as follows:~~based on the credit ratings assigned to the senior, unsecured, non-credit enhanced long-term debt of ETO.

~~Natural gas operations,~~Acquisition of SemGroup by ET

On September 16, 2019, ET entered into a definitive merger agreement to acquire SemGroup in a unit and cash transaction. Total consideration, including the ~~following:~~

~~natural gas midstream and intrastate transportation and storage; and~~

~~interstate natural gas transportation and storage.~~

~~Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.~~

~~RECENT DEVELOPMENTS~~

~~Permian Gulf Coast Pipeline Joint Venture~~

Inassumption of debt, is approximately $5 billion, based on the closing price of ET common units on September ~~2018, ETP, Magellan Midstream Partners, L.P., MPLX LP and Delek US Holdings, Inc.~~ announced that they have received sufficient commitments to proceed with plans to construct a new 30-inch diameter common carrier pipeline, the Permian Gulf Coast (“PGC”) pipeline, to transport crude oil from the Permian Basin to the Texas Gulf Coast region.13, 2019. The ~~600-mile PGC pipeline system~~transaction is expected to ~~be operational~~close in mid-2020 with multiple Texas origins. The pipeline system will have the strategic capability to transport crude oil to ETP’s Nederland, Texas terminal for ultimate delivery through its distribution system. The project islate 2019 or early 2020, subject to ~~receipt of~~the approval by SemGroup’s stockholders and other customary regulatory ~~and Board approvals~~approvals. ET expects to contribute the SemGroup assets to the Partnership subsequent to closing 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 to a terminal near Midland, Texas on behalf of the ~~respective entities.~~

~~ETE~~joint venture. The diesel fuel pipeline had an initial capacity of 30,000 barrels per day and ~~ETP Simplification Transaction~~

~~In October 2018, Energy Transfer Equity, L.P. (“ETE”) and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly-owned subsidiary of ETE~~was successfully commissioned in a unit-for-unit exchange (the “ETE-ETP Merger”). In connection with the transaction, ETP unitholders (other than ETE and its subsidiaries) received 1.28 common units of ETE for each common unit of ETP they owned.

~~Immediately prior to the closing of the ETE-ETP Merger, the following also occurred:~~

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

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

~~Immediately prior to the closing of the ETE-ETP Merger, ETE contributed the following to ETP:~~

~~2,263,158 common units representing limited partner interests in Sunoco LP to ETP in exchange for 2,874,275 ETP common units;~~

~~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 ETP in exchange for 42,812,389 ETP common units;~~

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a 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 to ETP in exchange for 37,557,815 ETP common units.August 2019.

Series DE Preferred Units Issuance

In ~~July 2018, ETP~~April 2019, ETO issued ~~17.8~~32 million of its ~~7.625%~~7.600% Series DE Preferred Units at a price of $25 per unit, ~~resulting in~~including 4 million Series E Preferred Units pursuant to the underwriters’ exercise 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 ~~$445 million.~~their option. The net proceeds were used to repay amounts outstanding under ~~ETP’s revolving credit facility~~ETO’s Five-Year Credit Facility and for general partnership purposes.

~~ETP~~ET-ETO Senior Notes Exchange

In March 2019, ETO issued approximately $4.21 billion aggregate principal amount of senior notes to settle and exchange approximately 97% of ET’s outstanding senior notes. In connection with this exchange, ETO issued $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, $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.

ETO Senior Notes Offering and Redemption

In ~~June 2018, ETP~~January 2019, ETO issued ~~$500~~$750 million aggregate principal amount of ~~4.20%~~4.50% senior notes due ~~2023, $1.00~~2024, $1.50 billion aggregate principal amount of ~~4.95%~~5.25% senior notes due ~~2028, $500 million aggregate principal amount of 5.80% senior notes due 2038~~2029 and ~~$1.00~~$1.75 billion aggregate principal amount of ~~6.00%~~6.25% senior notes due ~~2048.~~2049. The ~~$2.96~~$3.96 billion net proceeds from the offering were used to repay in full ET’s outstanding senior secured term loan, to redeem

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outstanding senior notes at maturity, to repay a portion of the borrowings ~~outstanding~~ under ~~ETP’s~~the Partnership’s revolving credit facility and for general partnership purposes.

~~Old Ocean Joint Venture Formation~~Panhandle Senior Notes Redemption

In ~~May 2018, ETP~~June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and Enterprise Products Partners L.P. announced the formation of a joint venture to resume service on the Old Ocean natural gas pipeline. The 24-inch diameter pipeline resumed service in May 2018 and ETP is the operator. Additionally, both parties are in the process of expanding their jointly owned North Texas 36-inch pipeline that will provide more capacity from West Texas for deliveries into the Old Ocean pipeline. The North Texas pipeline expansion project is expected to be complete by January 1, 2019.were repaid with borrowings under an affiliate loan agreement with ETO.

~~Acquisition of HPC~~Bakken Senior Notes Offering

~~ETP previously owned a 49.99% interest in HPC, which owns RIGS.~~ In April 2018, ETP acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETP’s financial statements; beginning in April 2018, RIGS is reflected asMarch 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 2024 and $850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in ~~ETP’s financial statements.~~

~~Series C Preferred Units Issuance~~

~~In April 2018, ETP issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in total gross~~net proceeds ~~of $450 million. The 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

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 borrowings under ~~ETP’s revolving~~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

~~CDM Contribution~~

~~New Ethane Export Facility Joint Venture~~

In March 2018, ETP and Satellite Petrochemical USA Corp. (“Satellite”) entered into definitive agreements to form a joint venture, Orbit Gulf Coast NGL Exports, LLC (“Orbit”), with the purpose of constructing a new export terminal on the United States Gulf Coast to provide ethane to Satellite for consumption at their ethane cracking facilities in China. At the terminal, Orbit will construct an 800 MBbls refrigerated ethane storage tank, a 175 MBbls/d ethane refrigeration facility and a 20-inch ethane pipeline originating at ETP’s Mont Belvieu Fractionators that will make deliveries to the terminal as well as domestic markets in the region. ETP will be the operator of the Orbit assets, provide storage and marketing services for Satellite and provide Satellite with approximately 150 MBbls/d of ethane under a long-term, demand-based agreement. Additionally, ETP will construct and

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wholly own the infrastructure that is required to both supply ethane to the pipeline and to load the ethane on to very large ethane carriers destined for Satellite’s newly constructed ethane crackers in China’s Jiangsu Province. Subject to Chinese Governmental approval, it is anticipated that the Orbit export terminal will be ready for commercial service in the fourth quarter of 2020.

~~Sunoco LP Common Unit Repurchase~~

Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective ~~December 22, 2017,~~January 2018, the 2017 Tax and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy ~~Statement because it is non-binding policy and parties will have the opportunity to address the policy as applied in future cases.~~Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. In light of the rehearing order, the impacts of the FERC’s policy on the treatment of income taxes may have on the rates ~~ETP~~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. It is unknown at this time what actions that the FERC will take, if any, following receipt of responses to the 2017 Tax Law NOI and any potential impacts from final rules or policy statements issued following the 2017 Tax Law NOI on the rates ETP can charge for FERC regulated transportation services.

~~Included~~Also included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that are generally the same as proposed 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:~~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 ~~only as required related~~ to reflect the ~~Tax Act and the Revised Policy Statement,~~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 ~~are scheduled to file~~filed their respective FERC Form No. 501-Gs byon or about November 8, ~~2018.~~2018, and Rover, FGT, Transwestern and MEP ~~are scheduled to file~~filed their respective FERC Form No. 501-Gs byon or about December 6, 2018. ~~At this time, we cannot predict~~By order issued January 16, 2019, the ~~outcome~~FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the ~~Final Rule, but adoption~~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 ~~regulation could ultimately result in a rate proceeding that may impact~~Natural Gas Act to determine whether the rates ~~ETP is permitted to charge its customers~~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 ~~regulated transportation services.~~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

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increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or 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 ~~ETP’s~~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 ~~will~~may 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 ~~Liquids Transportation~~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 1.1 of each year. With respect to ~~liquids and refined products~~common carrier 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.

Results of Operations

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as ~~a measure~~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. ~~Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments.~~ Segment Adjusted EBITDA ~~reflects~~and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the ~~Partnership’s proportionate ownership.~~same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section ~~below~~ titled “Segment Operating Results.” ~~Total Segment~~ Adjusted EBITDA ~~as presented below, is equal to the consolidated measure of Adjusted EBITDA, which~~ 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. ~~Our definition of total or consolidated Adjusted EBITDA is consistent with the definition of Segment Adjusted EBITDA above.~~

As discussed in Note 1 of the Partnership’s consolidated financial statements included in “Item 1. Financial Statements,” ~~during~~ the ~~fourth quarter~~Energy Transfer Merger in October 2018 resulted in the retrospective adjustment of ~~2017,~~ the ~~Partnership elected~~Partnership’s consolidated financial statements to ~~change its method~~reflect consolidation beginning January 1, 2018 of ~~inventory costing to weighted-average cost~~Sunoco LP and Lake Charles LNG and April 2, 2018 for ~~certain~~USAC.

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inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

Consolidated Results


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017*			Change			2018			2017*			Change			2019			2018			Change			2019			2018			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	221		$	163		$	58		$	621		$	480		$	141		$	235		$	221		$	14		$	777		$	621		$	156
Interstate transportation and storage	416			273			143			1,069			800			269			442			459			(17		)	1,358			1,200			158
Midstream	434			356			78			1,225			1,088			137			411			434			(23		)	1,205			1,225			(20		)
NGL and refined products transportation and services	498			439			59			1,410			1,208			202			667			498			169			1,923			1,410			513
Crude oil transportation and services	682			420			262			1,694			835			859			700			682			18			2,257			1,694			563
Investment in Sunoco LP																			192			208			(16		)	497			457			40
Investment in USAC																			104			90			14			310			185			125
All other	78			133			(55		)	242			363			(121		)	37			(6		)	43			83			69			14
Total	2,329			1,784			545			6,261			4,774			1,487
Adjusted EBITDA (consolidated)																			2,788			2,586			202			8,410			6,861			1,549
Depreciation, depletion and amortization	(636		)	(596		)	(40		)	(1,827		)	(1,713		)	(114		)	(782		)	(747		)	(35		)	(2,334		)	(2,100		)	(234		)
Interest expense, net	(387		)	(352		)	(35		)	(1,091		)	(1,020		)	(71		)
Gain on Sunoco LP common unit repurchase	—			—			—			172			—			172
Loss on deconsolidation of CDM	—			—			—			(86		)	—			(86		)
Interest expense, net of capitalized interest																			(575		)	(446		)	(129		)	(1,680		)	(1,246		)	(434		)
Impairment losses																			(12		)	—			(12		)	(62		)	—			(62		)
Gains (losses) on interest rate derivatives	45			(8		)	53			117			(28		)	145			(175		)	45			(220		)	(371		)	117			(488		)
Non-cash compensation expense	(20		)	(19		)	(1		)	(61		)	(57		)	(4		)	(27		)	(27		)	—			(85		)	(82		)	(3		)
Unrealized gains (losses) on commodity risk management activities	97			(81		)	178			(255		)	17			(272		)	64			97			(33		)	90			(255		)	345
Losses on extinguishments of debt																			—			—			—			(2		)	(109		)	107
Inventory valuation adjustments																			(26		)	(7		)	(19		)	71			50			21
Adjusted EBITDA related to unconsolidated affiliates	(257		)	(279		)	22			(670		)	(765		)	95			(161		)	(179		)	18			(470		)	(503		)	33
Equity in earnings of unconsolidated affiliates	113			127			(14		)	147			139			8			82			87			(5		)	224			258			(34		)
Adjusted EBITDA related to discontinued operations																			—			—			—			—			25			(25		)
Other, net	13			27			(14		)	100			79			21			103			32			71			211			58			153
Income before income tax (expense) benefit	1,297			603			694			2,807			1,426			1,381
Income tax (expense) benefit	61			112			(51		)	32			(22		)	54
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	$	1,358		$	715		$	643		$	2,839		$	1,404		$	1,435		$	1,224		$	1,491		$	(267	)	$	3,786		$	2,802		$	984

* As adjusted.Adjusted EBITDA (consolidated). For the three months ended September 30, 2019 compared to the same period last year, Adjusted EBITDA increased $202 million, or 8%. The increase was primarily due to the impact of multiple revenue-generating 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 $50 million impact (net of $27 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 increase in Adjusted EBITDA was primarily due to stronger demand on existing assets.

~~See~~

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For the ~~detailed~~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 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.

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization ~~expense~~ increased for the three and nine months ended September 30, ~~2018~~2019 compared to the same ~~period~~periods last year primarily due to additional depreciation and amortization from assets recently placed in service. ~~These increases were partially offset by~~For the ~~deconsolidation of CDM in April 2018, which reduced depreciation and amortization expense by $43 million and $78 million for the three and~~ nine months ended September 30, ~~2018, respectively, compared~~2019, depreciation, depletion and amortization also increased due to the ~~prior periods.~~acquisition of USAC on April 2, 2018.

Interest Expense, ~~net.~~Net of Capitalized Interest. Interest expense, net of capitalized interest, increased for the three and nine months ended September 30, ~~2018~~2019 compared to the same ~~period~~periods last year primarily ~~attributable~~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 ~~ETP~~ETO senior note issuances, ~~partially offset~~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 $7 million for the three months ended September 30, 2019 recognized by ~~a decrease~~USAC primarily due to its senior notes issuance in ~~credit facility borrowings.~~

~~Table~~March 2019 and an increase of ~~Contents~~

~~Gain on Sunoco LP Common Unit Repurchase.~~ ~~In connection with Sunoco LP’s repurchase of its common units in February 2018, the Partnership recognized a gain of $172~~$43 million ~~during~~for the nine months ended September 30, ~~2018.~~

~~Loss on Deconsolidation~~2019 primarily due to the consolidation of ~~CDM.~~ ~~In connection with the CDM Contribution in~~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 primarily related to an increase in Sunoco LP’s total long-term debt.

Impairment Losses. Due to a decrease in the demand for storage on the Partnership’s interstate transportation and storage segment Southwest Gas natural gas storage assets, the Partnership ~~deconsolidated CDM and~~performed an interim impairment test on the assets of Southwest Gas during the three months ended September 30, 2019. As a result of the interim impairment test, the Partnership recognized a ~~loss~~goodwill impairment of ~~$86~~$12 million ~~during~~related to Southwest Gas, primarily due to decreases in projected future revenues and cash flows. No other impairments of the Partnership’s other assets were identified. In addition, for the nine months ended September 30, ~~2018.~~2019, Sunoco LP recognized an asset impairment of $47 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.

Gains (Losses) on Interest Rate ~~Derivatives.~~ ~~Gains~~Derivatives. Losses on interest rate derivatives during the three and nine months ended September 30, ~~2018~~2019 resulted from ~~increases~~decreases in forward interest rates, which caused our forward-starting swaps to ~~change~~decrease in value.

Unrealized Gains (Losses) on Commodity Risk Management ~~Activities.~~ 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 the nine months ended September 30, 2018 resulted from Sunoco LP’s senior note and term loan redemption in January 2018.

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.~~Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment ~~Operation~~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. ~~Includes~~ 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. For the three ~~and~~months ended September 30, 2019 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, ~~2018~~2019 compared to the same period last year, income tax expense ~~decreased~~increased primarily due to the ~~decrease in federal corporate income~~recognition of a favorable state tax rate ~~per~~change in the ~~Tax Act as well as $109 million~~prior period and ~~$179 million, respectively, of deferred~~an increase in income before tax ~~benefit adjustments during~~expense at our corporate subsidiaries in the ~~three and nine months ended September 30, 2018 as the result of a state statutory rate reduction.~~

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current period.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:


	Three Months Ended September 30,								Nine Months Ended September 30,									Three Months Ended September 30,							Nine Months Ended September 30,
	2018			2017		Change			2018			2017			Change			2019		2018		Change			2019		2018		Change
Equity in earnings (losses) of unconsolidated affiliates:
Equity in earnings of unconsolidated affiliates:
Citrus	$	42		$	35	$	7		$	102		$	86		$	16		$	44	$	42	$	2		$	115	$	102	$	13
FEP	14			14		—			41			39			2			15		14		1			43		41		2
MEP	7			9		(2		)	24			29			(5		)	1		7		(6		)	15		24		(9		)
Sunoco LP	29			35		(6		)	(106		)	(89		)	(17		)
USAC	(4		)	—		(4		)	(6		)	—			(6		)
Other	25			34		(9		)	92			74			18			22		24		(2		)	51		91		(40		)
Total equity in earnings of unconsolidated affiliates	$	113		$	127	$	(14	)	$	147		$	139		$	8		$	82	$	87	$	(5	)	$	224	$	258	$	(34	)

Adjusted EBITDA related to unconsolidated affiliates⁽¹⁾:
Adjusted EBITDA related to unconsolidated affiliates:
Citrus	$	96		$	99	$	(3	)	$	256		$	262		$	(6	)	$	92	$	96	$	(4	)	$	260	$	256	$	4
FEP	19			18		1			56			55			1			19		19		—			56		56		—
MEP	20			23		(3		)	62			66			(4		)	13		20		(7		)	52		62		(10		)
Sunoco LP	58			74		(16		)	126			211			(85		)
USAC	20			—		20			41			—			41
Other	44			65		(21		)	129			171			(42		)	37		44		(7		)	102		129		(27		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	257		$	279	$	(22	)	$	670		$	765		$	(95	)	$	161	$	179	$	(18	)	$	470	$	503	$	(33	)

Distributions received from unconsolidated affiliates:
Citrus	$	52		$	50	$	2		$	125		$	113		$	12		$	54	$	52	$	2		$	128	$	125	$	3
FEP	18			18		—			50			28			22			20		18		2			53		50		3
MEP	9			13		(4		)	40			106			(66		)	7		9		(2		)	33		40		(7		)
Sunoco LP	21			36		(15		)	79			108			(29		)
USAC	10			—		10			20			—			20
Other	34			27		7			76			80			(4		)	22		34		(12		)	80		76		4
Total distributions received from unconsolidated affiliates	$	144		$	144	$	—		$	390		$	435		$	(45	)	$	103	$	113	$	(10	)	$	294	$	291	$	3


⁽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.

~~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~~. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

~~Non-cash compensation expense~~. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

~~Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA.~~


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


•	Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

•

Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.

In the 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.

~~Following is a reconciliation of ETP’s segment margin to operating income, as reported in its consolidated statements of operations:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 2018 2017
Segment Margin:
Intrastate transportation and storage $ 284
$ 167
$ 722
$ 551
Interstate transportation and storage 395
224
1,039
666
Midstream 622
530
1,768
1,614
NGL and refined products transportation and services 634
483
1,821
1,558
Crude oil transportation and services 944
548
1,954
1,194
All other 25
112
177
290
Intersegment eliminations (8 ) (13 ) (23 ) (24 )
Total segment margin 2,896
2,051
7,458
5,849

Less:
Operating expenses 632
571
1,863
1,603
Depreciation, depletion and amortization 636
596
1,827
1,713
Selling, general and administrative 123
105
347
335
Operating income $ 1,505
$ 779
$ 3,421
$ 2,198

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Intrastate Transportation and Storage


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Change			2018			2017			Change			2019			2018			Change			2019			2018			Change
Natural gas transported (BBtu/d)	12,146			8,951			3,195			10,592			8,698			1,894			12,560			12,146			414			12,221			10,592			1,629
Withdrawals from storage natural gas inventory (BBtu)	—			—			—			17,703			23,093			(5,390		)	—			—			—			—			17,703			(17,703		)
Revenues	$	922		$	773		$	149		$	2,610		$	2,342		$	268		$	764		$	922		$	(158	)	$	2,385		$	2,610		$	(225	)
Cost of products sold	638			606			32			1,888			1,791			97			501			638			(137		)	1,473			1,888			(415		)
Segment margin	284			167			117			722			551			171			263			284			(21		)	912			722			190
Unrealized (gains) losses on commodity risk management activities	(12		)	22			(34		)	33			16			17			19			(12		)	31			3			33			(30		)
Operating expenses, excluding non-cash compensation expense	(51		)	(40		)	(11		)	(141		)	(124		)	(17		)	(48		)	(51		)	3			(137		)	(141		)	4
Selling, general and administrative expenses, excluding non-cash compensation expense	(7		)	(6		)	(1		)	(20		)	(17		)	(3		)	(7		)	(7		)	—			(20		)	(20		)	—
Adjusted EBITDA related to unconsolidated affiliates	6			19			(13		)	26			53			(27		)	7			6			1			18			26			(8		)
Other	1			1			—			1			1			—			1			1			—			1			1			—
Segment Adjusted EBITDA	$	221		$	163		$	58		$	621		$	480		$	141		$	235		$	221		$	14		$	777		$	621		$	156

Volumes. For the three ~~and nine~~ months ended September 30, ~~2018~~2019 compared to the same period last year, transported volumes increased primarily due to ~~favorable market pricing, as well as~~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 ~~discussed in “Recent Developments” above.~~well as the impact of favorable market pricing spreads.

Segment Margin. The components of ~~ETP’s~~our intrastate transportation and storage segment margin were as follows:


	Three Months Ended September 30,								Nine Months Ended September 30,									Three Months Ended September 30,								Nine Months Ended September 30,
	2018		2017			Change			2018			2017			Change			2019			2018		Change			2019			2018			Change
Transportation fees	$	141	$	109		$	32		$	392		$	337		$	55		$	150		$	141	$	9		$	452		$	392		$	60
Natural gas sales and other (excluding unrealized gains and losses)	110		55			55			309			149			160			112			110		2			405			309			96
Retained fuel revenues (excluding unrealized gains and losses)	16		15			1			42			43			(1		)	14			16		(2		)	37			42			(5		)
Storage margin (excluding unrealized gains and losses)	5		10			(5		)	12			38			(26		)	6			5		1			21			12			9
Unrealized gains (losses) on commodity risk management activities	12		(22		)	34			(33		)	(16		)	(17		)	(19		)	12		(31		)	(3		)	(33		)	30
Total segment margin	$	284	$	167		$	117		$	722		$	551		$	171		$	263		$	284	$	(21	)	$	912		$	722		$	190

Segment Adjusted EBITDA. For the three months ended September 30, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~our intrastate transportation and storage segment increased due to the net impacts of the following:


•	an increase of $9 million in transportation fees primarily due to increased utilization of our Texas pipelines;

an increase of ~~$55~~$2 million in realized natural gas sales and other ~~margin~~ due to higher realized gains from pipeline optimization activity; and


•	an increase of $1 million in realized storage margin primarily due to higher storage fees; partially offset by


•	a decrease of $2 million in retained fuel revenue primarily due to lower gas prices.

an increase of $7 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; and

a net increase of $6 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of

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~~$25 million, $5 million and $2 million, respectively, and a decrease of $12 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by~~

~~a decrease of $5 million in realized storage margin primarily due to lower realized derivative gains.~~

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~our intrastate transportation and storage segment increased due to the net impacts of the following:

~~an increase of $160~~


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


•	an increase of $36 million in transportation fees, excluding the impact of consolidating RIGS as discussed below, 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 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 million in realized storage margin 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; partially offset by


•	a decrease of $5 million in retained fuel revenues primarily due to lower natural gas prices.

~~an increase~~

Table of ~~$6 million~~ ~~in transportation fees, excluding the impact of consolidating RIGS as discussed above, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; and~~Contents

a net increase of $3 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $49 million, $11 million and $4 million, respectively, and a decrease of $31 million in Adjusted EBITDA related to unconsolidated affiliates; partially offset by

~~a decrease of $26 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory; and~~

~~a decrease of $1 million in retained fuel revenues due to lower natural gas pricing.~~

Interstate Transportation and Storage


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Change			2018			2017			Change			2019			2018			Change			2019			2018			Change
Natural gas transported (BBtu/d)	10,155			6,075			4,080			9,029			5,678			3,351			11,407			10,155			1,252			11,254			9,029			2,225
Natural gas sold (BBtu/d)	18			19			(1		)	17			18			(1		)	17			18			(1		)	18			17			1
Revenues	$	395		$	224		$	171		$	1,039		$	666		$	373		$	479		$	445		$	34		$	1,470		$	1,187		$	283
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(97		)	(79		)	(18		)	(296		)	(220		)	(76		)	(141		)	(104		)	(37		)	(425		)	(312		)	(113		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(19		)	(14		)	(5		)	(53		)	(33		)	(20		)	(17		)	(20		)	3			(49		)	(55		)	6
Adjusted EBITDA related to unconsolidated affiliates	135			140			(5		)	374			383			(9		)	124			135			(11		)	368			374			(6		)
Other	2			2			—			5			4			1			(3		)	3			(6		)	(6		)	6			(12		)
Segment Adjusted EBITDA	$	416		$	273		$	143		$	1,069		$	800		$	269		$	442		$	459		$	(17	)	$	1,358		$	1,200		$	158

Volumes. For the three and nine months ended September 30, ~~2018~~2019 compared to the same ~~period~~periods last year, transported volumes reflected an increase of 1,252 BBtu/d and 2,225 BBtu/d, respectively, as a result of the ~~initiation of service on~~following: the Rover pipeline; increases of 772 BBtu/d and 625 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to increased utilization of higher contracted capacity; and an increase of 398 BBtu/d on the Tiger pipeline ~~as a result of~~being placed fully in-service in November 2018; production increases in the Haynesville Shale and deliveries ~~into~~to intrastate ~~markets.~~

~~For the nine months ended September 30, 2018 compared to the same period last year, transported volumes reflected increases~~markets resulting in increased deliveries off of ~~1,817 BBtu/d as a result~~our Tiger pipeline; and increased utilization of ~~the initiation of service on the Rover pipeline; increases of 594 BBtu/d and 428 BBtu/d~~higher contracted capacity on the Panhandle and Trunkline pipelines, respectively, due to higher demand resulting from colder weather and increased utilization by the Rover pipeline; 397 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into the intrastate markets and 104 BBtu/d on the Transwestern pipeline resulting from favorable market opportunities in the midcontinent and Waha areas from the Permian supply basin.pipelines.

Segment Adjusted EBITDA. For the three months ended September 30, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~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 of $24 million in reservation fees from placing the Rover pipeline fully in-service and $7 million from increased utilization of our Transwestern and Trunkline pipelines; and

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

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

an increase of $128 million associated with the Rover pipeline with increases of $149 million in revenues, $14 million in net operating expenses and $7 million in selling, general and administrative expenses; and

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an aggregate increase of $22 million in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines; partially offset by

an increase of $4$228 million ~~in operating expenses, excluding the incremental expenses related to~~from placing the Rover pipeline ~~discussed above,~~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 million in Adjusted EBITDA from unconsolidated affiliates primarily due to a $10 million decrease in earnings from MEP as a result of lower capacity being re-contracted and lower rates on expiring contracts, offset by a $3 million increase from new fixed transportation contracts on Citrus.

Midstream



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Gathered volumes (BBtu/d)	13,955			12,774			1,181			13,278			11,890			1,388
NGLs produced (MBbls/d)	574			583			(9		)	567			533			34
Equity NGLs (MBbls/d)	30			32			(2		)	32			31			1
Revenues	$	1,580		$	2,253		$	(673	)	$	4,496		$	5,741		$	(1,245	)
Cost of products sold	953			1,631			(678		)	2,678			3,973			(1,295		)
Segment margin	627			622			5			1,818			1,768			50
Operating expenses, excluding non-cash compensation expense	(202		)	(179		)	(23		)	(574		)	(512		)	(62		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(21		)	(19		)	(2		)	(63		)	(59		)	(4		)
Adjusted EBITDA related to unconsolidated affiliates	6			9			(3		)	21			25			(4		)
Other	1			1			—			3			3			—
Segment Adjusted EBITDA	$	411		$	434		$	(23	)	$	1,205		$	1,225		$	(20	)

Volumes. For the three months ended September 30, 2019 compared to the same period last year, gathered volumes increased primarily due to ~~slightly higher system gas expense~~new production in the Northeast, South Texas and ~~higher maintenance project costs~~Permian regions. For the three months ended September 30, 2019 compared to the same period last year, NGL production decreased due to ~~scope~~ethane rejection in the South Texas and ~~level of activity, offset by lower ad valorem taxes due to favorable valuations; and~~

~~a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily related to sale of capacity on MEP at lower rates and lower sales of short term firm capacity on Citrus.~~

~~Segment Adjusted EBITDA.~~ North Texas regions. For the nine months ended September 30, 2019 compared to the same period last year, gathered volumes and NGL production increased in the Northeast, 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 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.



	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2019		2018		Change
Gathering and processing fee-based revenues	$	517	$	458	$	59		$	1,488	$	1,319	$	169
Non-fee-based contracts and processing	110		164		(54		)	330		449		(119		)
Unrealized gains (losses) on commodity risk management activities	—		—		—			—		—		—
Total segment margin	$	627	$	622	$	5		$	1,818	$	1,768	$	50

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

Ana 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 ~~$247~~$11 million ~~associated with~~from increased throughput volumes in the ~~Rover pipeline with increases~~Permian region;

an increase of ~~$336 million in revenues, $70 million in net operating expenses and $19~~$2 million in selling, general and administrative ~~expenses;~~expenses due to an increase in allocated overhead costs; and

~~an aggregate increase~~

Table of $45 million in revenues, excluding the incremental revenues related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $8 million of lower reservation revenues on the Tiger pipeline due to a customer contract restructuring; partially offset byContents


•	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 $6$59 million in ~~operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily~~fee-based margin due to ~~higher maintenance project costs;~~volume growth in the Northeast, Permian and

a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short term firm capacity on Citrus and lower margins on MEP due to lower rates on renewals of expiring long term contracts, partially South Texas regions, offset by ~~lower legal fees on Citrus.~~declines in the Mid-Continent/Panhandle regions.

~~Midstream~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 Change 2018 2017 Change
Gathered volumes (BBtu/d) 12,774
11,090
1,684
11,890
10,764
1,126
NGLs produced (MBbls/d) 583
453
130
533
461
72
Equity NGLs (MBbls/d) 32
27
5
31
27
4
Revenues $ 2,253
$ 1,765
$ 488
$ 5,741
$ 5,017
$ 724
Cost of products sold 1,631
1,235
396
3,973
3,403
570
Segment margin 622
530
92
1,768
1,614
154
Unrealized (gains) losses on commodity risk management activities —
1
(1 ) —
(18 ) 18
Operating expenses, excluding non-cash compensation expense (179 ) (157 ) (22 ) (512 ) (470 ) (42 )
Selling, general and administrative expenses, excluding non-cash compensation expense (19 ) (26 ) 7
(59 ) (60 ) 1
Adjusted EBITDA related to unconsolidated affiliates 9
6
3
25
20
5
Other 1
2
(1 ) 3
2
1
Segment Adjusted EBITDA $ 434
$ 356
$ 78
$ 1,225
$ 1,088
$ 137

~~Volumes.~~Segment Adjusted EBITDA. For the ~~three and~~ nine months ended September 30, 2018 compared to the same periods last year, gathered volumes and NGL production increased primarily due to increases in the North Texas, Permian and Northeast regions, partially offset by smaller declines in other regions.

~~Table of Contents~~

~~Segment Margin. The components of ETP’s midstream segment margin were as follows:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 Change 2018 2017 Change
Gathering and processing fee-based revenues $ 456
$ 418
$ 38
$ 1,330
$ 1,262
$ 68
Non-fee-based contracts and processing (excluding unrealized gains and losses) 166
113
53
438
334
104
Unrealized gains (losses) on commodity risk management activities —
(1 ) 1
—
18
(18 )
Total segment margin $ 622
$ 530
$ 92
$ 1,768
$ 1,614
$ 154

~~Segment Adjusted EBITDA.~~ ~~For the three months ended September 30, 2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~our midstream segment ~~increased~~decreased due to the net impacts of the following:


•	a decrease of $119 million in non fee-based margin due primarily to lower NGL prices of $123 million and lower gas prices of $37 million, partially offset by an increase of $41 million due to increased throughput volume in the North Texas, South Texas and Permian regions;

an increase of ~~$38 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions;~~

~~an increase of $27 million in non-fee-based margin due to increased throughput volume in the South Texas and Permian regions;~~

~~an increase of $26 million in non-fee-based margin primarily due to higher crude oil and NGL prices;~~

~~a decrease of $7 million in selling, general and administrative expenses primarily due to a decrease of $3 million in merger and acquisition costs and a $3 million change in capitalized overhead; and~~

~~an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from ETP’s Aqua, Mi Vida and Ranch joint ventures; partially offset by~~

an increase of $22 million in operating expenses due to increases of $6 million in materials, $5 million in outside services and $4 million in maintenance project costs, as well as a $7 million change in capitalized overhead.

~~Segment Adjusted EBITDA.~~ ~~For the nine months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to ETP’s midstream segment increased due to the net impacts of the following:~~

~~an increase of $68 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions;~~

~~an increase of $57 million in non-fee-based margin primarily due to higher crude oil and NGL prices;~~

~~an increase of $47 million in non-fee-based margin due to increased throughput volume in the North Texas and Permian regions;~~

~~an increase of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from ETP’s Aqua, Mi Vida and Ranch joint ventures; and~~

~~a decrease of $1 million in selling, general and administrative expenses primarily due to lower office expenses; partially offset by~~

~~an increase of $42~~$62 million in operating expenses primarily due to increases of ~~$13~~$27 million in outside services, $12 million in ~~materials, $8~~maintenance project costs, and $12 million in employee ~~costs~~costs; and ~~$4 million in maintenance project costs as well as a $3 million change in capitalized overhead.~~


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


•	an increase of $169 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions.

~~Table of Contents~~

NGL and Refined Products Transportation and Services


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Change			2018			2017			Change			2019			2018			Change			2019			2018			Change
NGL transportation volumes (MBbls/d)	1,086			836			250			997			829			168			1,346			1,086			260			1,277			997			280
Refined products transportation volumes (MBbls/d)	627			612			15			628			626			2			552			627			(75		)	599			628			(29		)
NGL and refined products terminal volumes (MBbls/d)	858			782			76			784			780			4			963			858			105			948			784			164
NGL fractionation volumes (MBbls/d)	567			390			177			505			418			87			713			567			146			697			505			192
Revenues	$	3,063		$	2,070		$	993		$	8,177		$	6,115		$	2,062		$	2,878		$	3,063		$	(185	)	$	8,521		$	8,177		$	344
Cost of products sold	2,429			1,587			842			6,356			4,557			1,799			1,962			2,429			(467		)	6,136			6,356			(220		)
Segment margin	634			483			151			1,821			1,558			263			916			634			282			2,385			1,821			564
Unrealized losses on commodity risk management activities	26			56			(30		)	26			2			24			(81		)	26			(107		)	15			26			(11		)
Operating expenses, excluding non-cash compensation expense	(168		)	(106		)	(62		)	(448		)	(358		)	(90		)	(167		)	(168		)	1			(471		)	(448		)	(23		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(17		)	(13		)	(4		)	(52		)	(49		)	(3		)	(22		)	(17		)	(5		)	(67		)	(52		)	(15		)
Adjusted EBITDA related to unconsolidated affiliates	23			19			4			63			54			9			24			23			1			63			63			—
Other	—			—			—			—			1			(1		)	(3		)	—			(3		)	(2		)	—			(2		)
Segment Adjusted EBITDA	$	498		$	439		$	59		$	1,410		$	1,208		$	202		$	667		$	498		$	169		$	1,923		$	1,410		$	513

Volumes. For the three and nine months ended September 30, ~~2018~~2019 compared to the same periods last year, 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 ~~primarily from~~due to the ~~Permian region resulting from a ramp up in production from existing customers, higher throughput volumes~~initiation of service on the Mariner ~~West driven by end user facility constraints in the prior period and higher throughput from Mariner South.~~East 2 pipeline system.

Refined products transportation volumes decreased for the three and nine months ended September 30, 2019 compared to the same periods last year primarily due to the closure of the Philadelphia Energy Services refinery during the third quarter of 2019.

NGL and refined products terminal volumes increased for the three and nine months ended September 30, ~~2018~~2019 compared to the same periods last year primarily due to ~~higher throughput volumes from~~ the ~~Northeast and Southwest regions, partially offset by decreased throughput volumes from~~initiation of service on our Mariner East 2 pipeline which commenced operations in the ~~Midwest region.~~fourth quarter of 2018.

NGL and refined products terminal volumes increased for the three months ended September 30, 2018 compared to the same period last year primarily due to more volumes loaded at ETP’s Nederland terminal as propane export demand increased, as well as higher throughput volumes at ETP’s Marcus Hook Industrial Complex primarily due to increased production from the Marcellus region. For the nine months ended September 30, 2018 compared to the same period last year, NGL and refined products terminal volumes increased primarily due to more volumes loaded at ETP’s Nederland terminal as propane export demand increased, partially offset by lower refined product throughput volumes at ETP’s Eagle Point terminal and lower volumes at ETP’s refined products marketing terminals.

Table of Contents

Average fractionated volumes at ~~ETP’s~~our Mont Belvieu, Texas fractionation facility increased ~~45% and 21%~~ for the three and nine months ended September 30, ~~2018, respectively,~~2019 compared to the same periods last year primarily due to the commissioning of ~~ETP’s~~our fifth ~~fractionator~~and sixth fractionators in July 2018 ~~as well as increased volumes from Permian producers.~~and February 2019, respectively.

~~Table of Contents~~

Segment Margin. The components of ~~ETP’s~~our NGL and refined products transportation and services segment margin were as follows:


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Change			2018			2017			Change			2019			2018			Change			2019			2018			Change
Transportation margin																			$	474		$	322		$	152		$	1,259		$	878		$	381
Fractionators and refinery services margin	$	162		$	115		$	47		$	424		$	352		$	72		171			141			30			491			365			126
Transportation margin	322			246			76			878			720			158
Terminal services margin																			175			130			45			478			353			125
Storage margin	50			50			—			154			160			(6		)	57			50			7			166			154			12
Terminal services margin	109			90			19			294			258			36
Marketing margin	17			38			(21		)	97			70			27			(42		)	17			(59		)	6			97			(91		)
Unrealized losses on commodity risk management activities	(26		)	(56		)	30			(26		)	(2		)	(24		)	81			(26		)	107			(15		)	(26		)	11
Total segment margin	$	634		$	483		$	151		$	1,821		$	1,558		$	263		$	916		$	634		$	282		$	2,385		$	1,821		$	564

Segment Adjusted EBITDA. For the three months ended September 30, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~our NGL and refined products transportation and services segment increased due to the net impacts of the following:

an increase of ~~$76~~$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 ~~$63~~$54 million increase resulting from higher ~~producer~~throughput volumes received from the Permian region on ~~ETP’s~~our Texas NGL pipelines, and an $11 million increase due to higher throughput volumes ~~on Mariner West driven by end user facility constraints in the prior period, an $8 million increase due to higher throughput volumes~~received from the ~~Eagle Ford~~Barnett and Barnett regions, a $3 million increase due to higher throughput volumes in ETP’s Northeast refined products system and a $3 million increase due to higher throughput volumes on Mariner South and Mariner East 1 NGL systems. These increases were partially offset by a $7 million decrease resulting from the timing of deficiency revenue recognition and a $5 million decrease from lower volumes from the Southeast Texas ~~region;~~regions;


•	an increase of $45 million in terminal services margin primarily due to the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018;

an increase of ~~$47~~$30 million in fractionation and refinery services margin ~~due to a $40 million increase~~primarily resulting from the commissioning of ~~ETP’s fifth~~our sixth fractionator in ~~July 2018~~February 2019 and higher NGL volumes from the Permian region feeding ~~ETP’s~~our Mont Belvieu fractionation ~~facility,~~facility. This increase was partially offset by a $4$3 million decrease resulting from a reclassification between our fractionation and storage margins; and

an increase ~~from Mariner South as more cargoes were loaded~~of $7 million in storage margin primarily due to ~~increased demand for export and~~ a $3 million increase from ~~blending gains as~~throughput pipeline fees collected at our Mont Belvieu storage facility, a ~~result of improved market pricing; and~~

~~an increase of $19 million in terminal services margin due to a $9~~$3 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $6 million increase at ETP’s Nederland terminal due to increased demand for propane exportsreclassification between our storage and a $6 million increase due to higher throughput at ETP’s Marcus Hook Industrial Complex. These increases were partially offset by a $2 million decrease due to reduced rental fees at ETP’s Eagle Point facility;fractionation margins; partially offset by

an increase of $62 million in operating expenses due to increases of $25 million from higher throughput on ETP’s fractionator, pipeline and terminal assets and the commissioning of ETP’s fifth fractionator in July 2018, $10 million due to a legal settlement in the prior period, $9 million resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, $7 million due to the timing of maintenance projects and higher overhead allocations, $6 million due to environmental reserves and $5 million due to ad valorem tax expense; and

a decrease of ~~$21~~$59 million in marketing margin primarily due to ~~a $13 million decrease in~~lower optimization gains from ETP’s Mont Belvieu marketing activities, a $4 million decrease from sales of propane and other products at ETP’s Marcus Hook Industrial Complex and a $2 million decrease from ETP’s butane blending operations resulting from ~~a decrease in blending volumes.~~less favorable market conditions and an $8 million write down on the value of stored NGL inventory; and


•	an increase of $5 million in selling, general and administrative expenses due to a $3 million increase in allocated overhead costs and a $2 million increase in legal fees.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~our NGL and refined products transportation and services segment increased due to the net impacts of the following:

an increase of ~~$158~~$381 million in transportation margin primarily due to a ~~$141~~$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 ~~producer~~throughput volumes received from the Permian region on ~~ETP’s~~our Texas NGL pipelines, and a $22 million increase due to higher throughput volumes on Mariner West driven by end user facility constraints in the prior period, an $11 million increase resulting from a reclassification between ETP’s transportation and fractionation margins in the second quarter of 2018, a $4$21 million increase due to higher throughput volumes from the Barnett ~~region, a $4 million increase due to higher throughput volumes from ETP’s Northeast~~ and Southwest refined product systems and a $4 million increase due to higher throughput volumes on Mariner South due to system downtime in the prior period. These increases were partially offset by a $16 million decrease resulting from lower throughput on MarinerSoutheast Texas regions;

•

an increase of $126 million in fractionation and refinery services margin primarily due to a $142 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $10 million decrease resulting from a reclassification between our fractionation and storage margins and an $8 million decrease in refinery services margin primarily due to lower pricing spreads;

5862

Table of Contents

•

an increase of $125 million in terminal services margin primarily due to a $130 million increase due to the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018 and a $10 million increase due to higher throughput at our refined product terminals in the Northeast. These increases were partially offset by a $16 million decrease due to lower volumes from third party pipeline, truck and rail delivered into our Marcus Hook terminal; and

~~East 1~~an increase of $12 million in storage margin primarily due to ~~system downtime in 2018,~~ 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 ~~transported volumes from the Southeast Texas region and a $2 million decrease~~optimization gains resulting from less favorable market conditions and an $8 million write down on the ~~timing~~value of ~~deficiency revenue recognition;~~stored NGL inventory;

an increase of ~~$72~~$23 million in ~~fractionation and refinery services margin~~operating expenses primarily due to ~~a $63~~an $18 million increase ~~resulting from the commissioning of ETP’s~~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 ~~fractionator~~and sixth fractionators, which commenced service in July 2018 and higher NGL volumes from the Permian region feeding ETP’s Mont Belvieu fractionation facility, a $12 million increase from blending gains as a result of improved market pricing and an $8 million increase as more cargoes were loaded at ETP’s Mariner South export facility.February 2019, respectively. These increases were partially offset by an $11 million decrease ~~resulting from a reclassification between ETP’s~~in outside services on our transportation and ~~fractionation margins;~~

~~an increase of $36 million in~~ terminal services margin due to a $25 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $13 million increase at ETP’s Nederland terminal due to increased demand for propane exportsassets; and a $2 million increase due to favorable activity at ETP’s Marcus Hook Industrial Complex. These increases were partially offset by a $3 million decrease due to reduced rental fees at ETP’s Eagle Point facility and a $1 million decrease from ETP’s marketing terminal volumes primarily due to the sale of one of ETP’s terminals in April 2017;


•	an increase of $15 million iin selling, general and administrative expenses due to a $6 million increase in allocated overhead costs, a $4 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.

an increase of $27 million in marketing margin primarily due to a $17 million increase from ETP’s butane blending operations and an $11 million increase from sales of domestic propane and other products at ETP’s Marcus Hook Industrial Complex due to more favorable market prices; and

an increase of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to improved contributions from ETP’s unconsolidated refined products joint venture interests; partially offset by

an increase of $90 million in operating expenses primarily due to increases of $44 million from higher throughput on ETP’s fractionator, pipeline and terminal assets and the commissioning of ETP’s fifth fractionator in July 2018, $25 million resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, $10 million due to a legal settlement in the prior period, $10 million due to environmental reserves and $4 million due to the timing of maintenance projects and higher overhead allocations; and

a decrease of $6 million in storage margin primarily due to a $15 million decrease from the expiration and amendments to various NGL and refined products storage contracts, partially offset by an increase from throughput pipeline fees collected at ETP’s Mont Belvieu storage terminal.

Crude Oil Transportation and Services


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Change			2018			2017			Change			2019			2018			Change			2019			2018			Change
Crude transportation volumes (MBbls/d)	4,276			3,773			503			4,119			3,425			694			4,661			4,276			385			4,638			4,119			519
Crude terminals volumes (MBbls/d)	2,134			1,923			211			2,060			1,884			176			1,905			2,134			(229		)	2,125			2,060			65
Revenues	$	4,438		$	2,725		$	1,713		$	12,986		$	7,765		$	5,221		$	4,453		$	4,438		$	15		$	13,685		$	12,986		$	699
Cost of products sold	3,494			2,177			1,317			11,032			6,571			4,461			3,620			3,494			126			10,857			11,032			(175		)
Segment margin	944			548			396			1,954			1,194			760			833			944			(111		)	2,828			1,954			874
Unrealized (gains) losses on commodity risk management activities	(118		)	(1		)	(117		)	187			(3		)	190			(2		)	(118		)	116			(100		)	187			(287		)
Operating expenses, excluding non-cash compensation expense	(126		)	(119		)	(7		)	(397		)	(305		)	(92		)	(110		)	(126		)	16			(410		)	(397		)	(13		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(22		)	(13		)	(9		)	(64		)	(62		)	(2		)	(21		)	(22		)	1			(61		)	(64		)	3
Adjusted EBITDA related to unconsolidated affiliates	4			5			(1		)	14			11			3			1			4			(3		)	—			14			(14		)
Other																			(1		)	—			(1		)	—			—			—
Segment Adjusted EBITDA	$	682		$	420		$	262		$	1,694		$	835		$	859		$	700		$	682		$	18		$	2,257		$	1,694		$	563

Volumes. For the three and nine months ended September 30, ~~2018~~2019 compared to the same periods last year, crude transportation ~~volumes increased due to placing the Bakken pipeline in service in June 2017 as well as higher throughput on existing pipelines due to increased production in West Texas. For the three~~ and ~~nine months ended September 30, 2018 crude~~ terminal volumes benefited from an increase in barrels ~~delivered to ETP’s Nederland~~through our existing Texas pipelines and our Bakken pipeline. Crude terminal volumes decreased for the three month period as a result of the closure of a refinery that was the primary customer utilizing one of our northeast crude ~~terminal from the Bakken pipeline and from increased West Texas production.~~terminals.

~~Table of Contents~~

Segment Adjusted EBITDA. For the three months ended September 30, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~our crude oil transportation and services segment increased due to the net impacts of the following:

an increase of ~~$279~~$5 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to ~~the following:~~ a ~~$131~~$63 million increase ~~resulting~~ from higher throughput on our Texas crude pipeline system primarily due to increased production from ~~ETP’s~~the Permian region, a $50 million increase from higher throughput on the Bakken pipeline, and ~~from Permian producers on existing pipeline assets, as well as~~ a ~~$30~~$6 million increase ~~resulting primarily~~ from ~~placing ETP’s Permian Express 3 pipeline in service in the fourth quarter of 2017;~~higher ship loading and tank rental fees at our Nederland terminal; partially offset by a ~~$108~~$106 million ~~increase~~decrease (excluding a net change of ~~$117~~$116 million in unrealized gains and ~~losses)~~losses on commodity risk management activities) from ~~ETP’s~~our crude oil acquisition and marketing business primarily resulting from ~~more favorable market price~~non-cash inventory valuation adjustments and lower basis differentials between the ~~West Texas~~Permian producing region and the Nederland terminal on the Gulf Coast, ~~markets;~~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 ~~$10 million increase from higher throughput and ship loading fees at ETP’s Nederland terminal; partially offset by~~

~~an increase~~decrease of $9$16 million in ~~selling, general and administrative~~operating expenses primarily due to ~~increases~~the impact of ~~$4 million in overhead allocations, $2 million in employee costs and $2 million in insurance costs; and~~

~~an increase of $7 million in operating expenses due to~~certain intrasegment transactions discussed above, partially offset by a $5$17 million increase ~~due to higher throughput related expenses on existing assets~~in ad valorem taxes; and ~~a $2 million increase from placing ETP’s Permian Express 3 pipeline in service in the fourth quarter of 2017.~~


•	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, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~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 $950 million in segment margin (excluding unrealized losses on commodity risk management activities) primarily due to the following: a $541 million increase resulting primarily from placing ETP’s Bakken pipeline in service in the second quarter of 2017; a $86 million increase resulting from higher throughput, primarily from Permian producers, on existing pipeline assets; a $295 million increase (excluding a net change of $190 million in unrealized gains and losses) from ETP’s crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets; and a $25 million increase primarily from higher throughput and ship loading fees at ETP’s Nederland terminal; and

~~an increase of $3~~$14 million in Adjusted EBITDA related to unconsolidated affiliates due to ~~increased~~lower margin from jet fuel sales ~~from ETP’s~~by our joint ~~ventures; partially offset by~~ventures.

~~an increase~~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 ~~$92 million~~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 ~~operating expenses~~Sunoco LP segment decreased due to ~~a $37~~the net impacts of the following:


•	a decrease of $23 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier in the prior period, partially offset by an increase in motor fuel gallons sold; partially offset by


•	a net decrease of $6 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation, primarily as a result of lower lease expense and utilities.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 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 decrease of $45 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation, primarily due to the conversion of 207 retail sites to commission agent sites in April 2018; and


•	an increase of $25 million in Adjusted EBITDA from discontinued operations due to Sunoco LP’s retail divestment in January 2018; partially offset by

•

a decrease of $33 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a one-time benefit of approximately $25 million 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.

Investment in USAC



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Revenues	$	175		$	169		$	6		$	520		$	336		$	184
Cost of products sold	23			24			(1		)	69			44			25
Segment margin	152			145			7			451			292			159
Operating expenses, excluding non-cash compensation expense	(35		)	(42		)	7			(102		)	(80		)	(22		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(13		)	(15		)	2			(39		)	(34		)	(5		)
Other	—			2			(2		)	—			7			(7		)
Segment Adjusted EBITDA	$	104		$	90		$	14		$	310		$	185		$	125

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

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 USAC segment increased due to the net impacts of the following:


•	an increase of $7 million in segment margin primarily due to an increase in demand for compression services driven by increased U.S. production of crude oil and natural gas;

•

a decrease 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 million in selling, general and administrative expenses primarily due to transaction related expenses as a result of transactions completed during 2018.

Amounts reflected above for the nine months ended September 30, 2019 reflects the consolidated results of USAC. Changes between periods are primarily ~~resulting from placing ETP’s Bakken pipeline in service in~~due to the ~~second quarter~~consolidation of ~~2017; a $36 million increase to throughput related costs on existing assets; a $19 million increase resulting from~~USAC beginning April 2, 2018, the ~~addition~~date ET obtained control of ~~certain joint venture transportation assets in the second quarter~~USAC.

Table of ~~2017; a $7 million increase in overhead allocations; and a $4 million increase from ad valorem taxes; partially offset by an $11 million decrease in insurance and environmental related expenses.~~Contents

All Other

Three Months Ended
September 30, Nine Months Ended
September 30,
2018 2017 Change 2018 2017 Change
Revenues $ 525
$ 683
$ (158 ) $ 1,598
$ 2,249
$ (651 )
Cost of products sold 500
571
(71 ) 1,421
1,959
(538 )
Segment margin 25
112
(87 ) 177
290
(113 )
Unrealized (gains) losses on commodity risk management activities 7
3
4
9
(14 ) 23
Operating expenses, excluding non-cash compensation expense (9 ) (34 ) 25
(50 ) (86 ) 36
Selling, general and administrative expenses, excluding non-cash compensation expense (26 ) (34 ) 8
(63 ) (82 ) 19
Adjusted EBITDA related to unconsolidated affiliates 80
88
(8 ) 168
244
(76 )
Other and eliminations 1
(2 ) 3
1
11
(10 )
Segment Adjusted EBITDA $ 78
$ 133
$ (55 ) $ 242
$ 363
$ (121 )

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	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Revenues	$	441		$	525		$	(84	)	$	1,276		$	1,599		$	(323	)
Cost of products sold	393			500			(107		)	1,138			1,421			(283		)
Segment margin	48			25			23			138			178			(40		)
Unrealized (gains) losses on commodity risk management activities	1			7			(6		)	(4		)	9			(13		)
Operating expenses, excluding non-cash compensation expense	(39		)	(9		)	(30		)	(52		)	(50		)	(2		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(9		)	(26		)	17			(42		)	(63		)	21
Adjusted EBITDA related to unconsolidated affiliates	—			2			(2		)	1			1			—
Other and eliminations	36			(5		)	41			42			(6		)	48
Segment Adjusted EBITDA	$	37		$	(6	)	$	43		$	83		$	69		$	14

Amounts reflected in ~~ETP’s~~our all other segment primarily include:

ETP’s equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million Sunoco LP common units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units as of September 30, 2018 and September 30, 2017, respectively. The results above reflect Sunoco LP’s repurchase of 17,286,859 Sunoco LP common units owned by ETP in February 2018; however, the results above do not reflect ETE’s contribution of limited partner and general partner interests in Sunoco LP to ETP in connection with the ETE-ETP Merger in October 2018. For periods subsequent to the ETE-ETP Merger, ETP will reflect Sunoco LP as a consolidated subsidiary;

~~ETP’s~~our natural gas marketing ~~and~~operations;

our wholly-owned natural gas compression operations. Subsequent to ETP’s contribution of CDM to USAC in April 2018, ETP’s all other segment includes ETP’s equity method investment in USAC consisting of 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests. The results above do not reflect ETE’s contribution of limited partner and general partner interests in USAC to ETP in connection with the ETE-ETP Merger in October 2018. For periods subsequent to the ETE-ETP Merger, ETP will reflect USAC as a consolidated subsidiary;operations;

a ~~non-controlling~~noncontrolling interest in PES. Prior to PES’s reorganization in August 2018, ~~ETP’s~~ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent to the August 2018 reorganization, ~~ETP~~ETO holds an approximately 8%7.4% interest in PES and no longer reflects PES as an affiliate; and

~~ETP’s~~our investment in coal handling facilities.

Segment Adjusted EBITDA. For the three months ended September 30, ~~2018~~2019 compared to the same period last year, Segment Adjusted EBITDA related to ~~ETP’s~~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 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 of $13 million in gains from park and loan and storage activity;


•	an increase of $9 million in optimized gains on residue gas sales;


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


•	a decrease of $21 million in selling, general and administrative expenses primarily due to lower merger and acquisition and other expenses; partially offset by


•	a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC Segment; and


•	a decrease of $5 million due to lower revenue from our compressor equipment business.

a decrease of $16 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in Sunoco LP resulting from ETP’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018;

a decrease of $12 million due to ETP’s contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM contribution;

a decrease of $12 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in PES primarily due to ETP’s lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018;

~~an increase of $7 million in general and administrative expenses from higher professional expenses;~~

~~a decrease of $6 million due to losses from commodity trading and risk management activities; and~~

~~a decrease of $3 million primarily due to lower margin from ETP’s compression equipment business.~~

~~Segment Adjusted EBITDA.~~ ~~For the nine months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to ETP’s all other segment decreased due to the net impacts of the following:~~

a decrease of $85 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in Sunoco LP resulting from ETP’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018;

a decrease of $31 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in PES primarily due to ETP’s lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018, as well as lower Adjusted EBITDA prior to August 2018; and

a decrease of $21 million due to ETP’s contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by

an increase of $10 million in Adjusted EBITDA primarily due to lower transport fees of $6 million resulting from the expiration of a capacity commitment on ETP’s Trunkline pipeline and a $7 million decrease in losses from the mark-to-market of physical system gas, offset by lower optimization gains on residue gas sales;

~~an increase of $6 million due to increased margin from ETP’s compression equipment business as several large projects were completed in June 2018; and~~

~~an increase of $4 million due to an equipment lease buyout in August 2017, partially offset by lower margin from depressed gas prices in West Texas.~~

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LIQUIDITY AND CAPITAL RESOURCES

Overview

~~ETP’s~~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 ~~2018~~2019 to be within the following ranges (excluding capital expenditures related to ~~the businesses contributed to ETP~~our investments in ~~connection with the ETE-ETP Merger in October 2018)~~Sunoco LP and USAC):


	Growth				Maintenance				Growth				Maintenance
	Low		High		Low		High		Low		High		Low		High
Intrastate transportation and storage	$	275	$	300	$	30	$	35	$	75	$	100	$	35	$	40
Interstate transportation and storage ⁽¹⁾	675		700		115		120		250		275		145		150
Midstream	975		1,025		130		135		675		700		145		150
NGL and refined products transportation and services	2,100		2,150		60		70		2,475		2,500		90		100
Crude oil transportation and services ⁽¹⁾	425		450		90		100		300		325		100		110
All other (including eliminations)	50		75		60		65		150		175		50		55
Total capital expenditures	$	4,500	$	4,700	$	485	$	525	$	3,925	$	4,075	$	565	$	605


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

For ~~2019, we expect~~2020, ETO expects growth capital expenditures to ~~spend~~be approximately $5$4 billion, ~~on organic growth projects.~~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 ~~reasons,~~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,~~control; however, we ~~include~~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 ~~proceeds of~~ borrowings under credit facilities, long-term debt, the issuance of additional ~~common~~preferred units ~~dropdown proceeds or the monetization of non-core assets~~ or a combination thereof.

Sunoco LP

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

USAC

USAC currently plans to spend approximately $28 million in maintenance capital expenditures during 2019, 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 million and $155 million in expansion capital expenditures during 2019. As of September 30, 2019, USAC has binding commitments to purchase $48 million of additional compression units and serialized parts, all of which USAC expects to be delivered throughout 2019 and 2020.

Cash Flows

Our ~~internally generated~~ cash flows may change in the future due to a number of factors, some of which we cannot control. These 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 of ~~acquisitions and deconsolidations)~~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 ~~derivative~~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.

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Nine months ended September 30, ~~2018~~2019 compared to nine months ended September 30, ~~2017.~~2018. Cash provided by operating activities during ~~2018~~2019 was ~~$5.10~~$6.06 billion compared to ~~$3.34 billion for 2017 and net income was $2.84 billion and $1.40~~$5.51 billion for 2018 and ~~2017,~~income from continuing operations was $3.79 billion and $3.07 billion for 2019 and 2018, respectively. The difference between ~~net~~ income from continuing operations and net cash provided by operating activities for the nine months ended September 30, ~~2018~~2019 primarily consisted of net changes in operating assets and liabilities (net of effects of ~~acquisitions and deconsolidations)~~acquisitions) of ~~$451~~$325 million and other non-cash items totaling ~~$1.51~~$2.35 billion.

The non-cash activity in ~~2018~~2019 and ~~2017~~2018 consisted primarily of depreciation, depletion and amortization of ~~$1.83~~$2.33 billion and ~~$1.71~~$2.10 billion, respectively, ~~and~~ non-cash compensation expense of ~~$61~~$85 million and ~~$57~~$82 million, respectively, inventory valuation adjustments of $71 million and $50 million, respectively, and deferred incomes taxes of $193 million and $2 million, respectively. Non-cash activity also included losses on extinguishments of debt in 2019 and 2018 of $2 million and $109 million, respectively, and impairment losses of $62 million in 2019.

Unconsolidated affiliate activity in ~~2018~~2019 and ~~2017~~2018 consisted of equity in earnings of ~~$147~~$224 million and ~~$139~~$258 million, respectively, and cash distributions received of ~~$328~~$254 million and ~~$319~~$229 million, respectively. ~~Non-cash activity in 2018 also included a gain on the sale of Sunoco LP units of $172 million and a loss on the deconsolidation of CDM of $86 million.~~

Cash paid for interest, net of capitalized interest, ~~capitalized,~~ was ~~$996 million~~$1.44 billion and ~~$1.01~~$1.17 billion for the nine months ended September 30, 2019 and 2018, ~~and 2017,~~ respectively.

Capitalized interest was ~~$221~~$145 million and ~~$211~~$222 million for the nine months ended September 30, ~~2018~~2019 and ~~2017,~~2018, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash ~~distributions from~~contributions to our joint ventures, and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Nine months ended September 30, ~~2018~~2019 compared to nine months ended September 30, ~~2017.~~2018. Cash used in investing activities during ~~2018~~2019 was ~~$3.07~~$4.42 billion compared to ~~$4.69~~$4.51 billion in ~~2017.~~2018. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for ~~2018~~2019 were ~~$4.87~~$4.12 billion compared to ~~$6.06~~$5.08 billion for ~~2017.~~2018. Additional detail related to our capital expenditures is provided in the table below. During ~~2018,~~2019, we received ~~$1.23 billion in~~$93 million of cash ~~related to~~proceeds from the ~~CDM Contribution and $540 million in cash related to the Sunoco LP common unit repurchase. During 2017, we received $2.00 billion in cash related to the Bakken equity~~ sale ~~to MarEn Bakken Company LLC, paid $280 million in cash for the acquisition~~ of ~~PennTex~~a noncontrolling interest in a subsidiary and paid ~~$264~~$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 ~~(net~~(including only our proportionate share of the Bakken, Rover and Bayou Bridge pipeline projects and net of contributions in aid of construction costs) for the nine months ended September 30, ~~2018:~~2019:


	Capital Expenditures Recorded During Period						Capital Expenditures Recorded During Period
	Growth		Maintenance		Total		Growth		Maintenance		Total
Intrastate transportation and storage(1)	$	233	$	37	$	270	$	61	$	39	$	100
Interstate transportation and storage	470		73		543		194		95		289
Midstream	731		113		844		535		105		640
NGL and refined products transportation and services	1,494		44		1,538		1,956		69		2,025
Crude oil transportation and services	333		33		366		239		58		297
Investment in Sunoco LP							80		23		103
Investment in USAC							137		22		159
All other (including eliminations)	43		42		85		134		29		163
Total capital expenditures	$	3,304	$	342	$	3,646	$	3,336	$	440	$	3,776


⁽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 months ended September 30, ~~2018~~2019 compared to nine months ended September 30, ~~2017.~~2018. Cash used in financing activities during ~~2018~~2019 was ~~$1.96~~$1.85 billion compared to ~~provided by financing activities of $1.37~~$3.67 billion for ~~2017. In 2018 and 2017,~~2018. During 2019, we received net proceeds of $780 million from ~~ETP common unit offerings~~the issuance of ~~$58 million and $2.16 billion, respectively. In~~preferred units. During 2018, we received ~~$867~~net proceeds of $57 million from common unit issuances and net proceeds of $868 million from preferred unit ~~offerings.~~issuances. During 2018, subsidiaries received net proceeds of $465 million from the issuance of redeemable noncontrolling interests. During 2019, we had a net increase in our debt level of ~~$410 million~~$3.12 billion compared to a net ~~increase~~decrease of ~~$1.24~~$1.04 billion for ~~2017. We have~~2018. In 2019 and 2018, we paid debt issuance costs of $114 million and $188 million, respectively.

In 2019, we paid distributions of $4.80 billion to our partners and our subsidiaries paid distributions of $1.11 billion to noncontrolling interests. In 2018, we paid distributions of $3.14 billion to ~~ETP’s unitholders in 2018 compared to $2.54 billion in 2017. We have also~~our partners and our subsidiaries paid distributions of ~~$536~~$816 million to noncontrolling interests, ~~in 2018 compared to $306 million in 2017.~~including predecessor distributions. In addition, ~~we have~~our subsidiaries received capital contributions of ~~$438~~$278 million in cash from noncontrolling interests in ~~2018~~2019 compared

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to ~~$919~~$438 million in ~~2017.~~2018. During 2018, we ~~also~~ repurchased ~~ETP~~ common units for cash of $24 million and ~~incurred debt issuance costs~~our subsidiaries also purchased $300 million of ~~$42 million. During 2017, we also repurchased our outstanding Legacy ETP Preferred Units for~~common units in cash.

Discontinued Operations

Cash flows from discontinued operations reflect cash ~~of $53 million and incurred debt issuance costs of $50 million.~~

~~Off-Balance Sheet Arrangements~~

~~Guarantee of Sunoco LP Notes~~

~~In connection with previous transactions whereby Retail Holdings contributed assets~~flows related to Sunoco ~~LP, Retail Holdings~~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 ~~a limited contingent guarantee~~by discontinued operations during 2018 was $2.74 billion, resulting from cash used in operating activities of ~~collection, but not~~$480 million, cash provided by investing activities of ~~payment, to Sunoco LP with respect to certain~~$3.21 billion and changes in cash included in current assets held for sale of Sunoco LP’s senior notes and $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).$11 million.

On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes, repaid and terminated the term loan and issued the following notes (the “Sunoco LP Notes”) for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:

~~$1.00 billion aggregate principal amount of 4.875% senior notes due 2023;~~

~~$800 million aggregate principal amount of 5.50% senior notes due 2026; and~~

~~$400 million aggregate principal amount of 5.875% senior notes due 2028.~~

Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.

In connection with the issuance of the Sunoco LP Notes, Sunoco LP entered into a registration rights agreement with the initial purchasers pursuant to which Sunoco LP agreed to complete an offer to exchange the Sunoco LP Notes for an issue of registered notes with terms substantively identical to each series of Sunoco LP Notes and evidencing the same indebtedness as the Sunoco LP Notes on or before January 23, 2019.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	September 30, 2018			December 31, 2017			September 30, 2019			December 31, 2018
ETP Senior Notes ⁽¹⁾	$	28,755		$	27,005
ETO Senior Notes ⁽¹⁾							$	36,117		$	28,755
Transwestern Senior Notes	575			575			575			575
Panhandle Senior Notes	386			785			236			385
Bakken Senior Notes							2,500			—
Sunoco LP Senior Notes and lease-related obligations							2,946			2,307
USAC Senior Notes							1,475			725
Credit facilities and commercial paper:
ETP $5.00 billion Revolving Credit Facility due December 2023 ⁽²⁾	1,780			2,292
ETP $1.00 billion 364-Day Credit Facility due November 2019	—			50
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			2,500			—			2,500
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023							154			700
USAC $1.60 billion Revolving Credit Facility due April 2023							395			1,050
Other long-term debt	4			5			4			7
Unamortized premiums, net of discounts and fair value adjustments	35			61			6			31
Deferred debt issuance costs	(188		)	(179		)	(286		)	(221		)
Total debt	33,847			33,094			46,730			40,508
Less: current maturities of long-term debt	2,649			407			14			2,655
Long-term debt, less current maturities	$	31,198		$	32,687		$	46,716		$	37,853

⁽¹⁾

~~Includes~~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 ~~9.70% senior notes~~5.75% note due ~~March 15, 2019 and $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019~~September 1, 2020 that were classified as long-term as of September 30, ~~2018~~2019 as management has the intent and ability to refinance the ~~borrowings~~borrowing on a long-term basis.


⁽²⁾	Includes ~~$1.57~~$2.15 billion and ~~$2.01~~$2.34 billion of commercial paper outstanding at September 30, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively.

~~ETP~~Recent Transactions

ETO Term Loan

ET-ETO Senior Notes ~~Offering~~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 ~~Redemption~~

$~~500~~1.14 billion aggregate principal amount of 7.50% senior notes due 2020;

$995 million aggregate principal amount of ~~4.20%~~4.25% senior notes due 2023;

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$~~1.00~~1.13 billion aggregate principal amount of ~~4.95%~~5.875% senior notes due ~~2028;~~2024; and

$~~500~~956 million aggregate principal amount of ~~5.80%~~5.50% senior notes due ~~2038; and~~2027.

~~$1.00 billion aggregate principal amount of 6.00% senior notes due 2048.~~

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.

~~ETP’s $650 million aggregate principal amount of 2.50% senior notes due June 15, 2018;~~

~~Panhandle’s~~ETO’s $400 million aggregate principal amount of ~~7.00%~~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 ~~15, 2018;~~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

~~ETP’s~~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

In March 2019, Sunoco LP issued $600 million aggregate principal amount of ~~6.70%~~6.00% senior notes due ~~July 1, 2018.~~

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 borrowings under

~~The aggregate amount paid to redeem these notes was approximately $1.65 billion.~~

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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

~~ETP~~ETO Five-Year Credit Facility

~~ETP~~ETO 364-Day Facility

~~Bakken~~Sunoco LP Credit Facility

~~In August 2016, ETP and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50~~Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”), which matures in ~~August 2019 (the “Bakken Credit Facility”).~~July 2023. As of September 30, ~~2018,~~2019, the ~~Bakken~~Sunoco LP Credit Facility had ~~$2.50 billion~~$154 million of outstanding borrowings ~~all~~and $8 million in standby letters of ~~which has been reflected in current maturities~~credit. As of ~~long-term debt on~~September 30, 2019 Sunoco LP had $1.34 billion of availability under the ~~Partnership’s consolidated balance sheet included in “Item 1. Financial Statements.”~~Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, ~~2018~~2019 was ~~3.85%~~4.04%.

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 30, 2019, the USAC Credit Facility had $395 million of outstanding borrowings and no outstanding letters of credit. As of September 30, 2019, USAC had $1.21 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $410 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.73%.

Covenants Related to Our Credit Agreements

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, ~~2018.~~2019.

CASH DISTRIBUTIONS

Distributions on common units declared and paid by the Partnership subsequent to December 31, 2017 but prior to the closing of the ETE-ETP Merger as discussed in Note 1 of the Partnership’s consolidated financial statements included in “Item 1. Financial Statements,” were as follows:

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~~Distributions on ETP’s~~ETO’s preferred units declared and/or paid by the Partnership subsequent to December 31, ~~2017~~2018 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


⁽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.

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Sunoco LP Cash Distributions

Distributions declared and/or paid by Sunoco LP subsequent to December 31, 2018 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

USAC Cash Distributions

Distributions declared and/or paid by USAC subsequent to December 31, 2018 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

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 ~~23, 2018.~~22, 2019. See Note 1 in “Item 1. Financial Statements” for information regarding recent changes to the Partnership’s critical accounting policies related to ~~revenue recognition.~~lease accounting.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 in “Item 1. Financial Statements” included in this Quarterly Report for information regarding recent accounting pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 filed with the SEC on February ~~23, 2018,~~22, 2019, 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, ~~2017.~~2018. Since December 31, ~~2017~~2018, 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, 2018							December 31, 2017							September 30, 2019							December 31, 2018
	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
Fixed Swaps/Futures	358		$	—		$	—	1,078		$	—		$	—	1,723		—			—		468		—			—
Basis Swaps IFERC/NYMEX ⁽¹⁾	69,685		8			1		48,510		2			1
Options – Puts	(17,273	)	—			—		13,000		—			—		—		—			—		10,000		—			—
Power (Megawatt):
Forwards	429,720		6			—		435,960		1			1		2,847,350		7			7		3,141,520		6			8
Futures	309,123		(1		)	1		(25,760	)	—			—		222,440		(1		)	—		56,656		—			—
Options – Puts	157,435		1			—		(153,600	)	—			1		515,317		—			—		18,400		—			—
Options – Calls	321,240		��			—		137,600		—			—		(756,153	)	(1		)	—		284,800		1			—
Crude (MBbls) – Futures	—		—			—		—		1			—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(7,705	)	(45		)	14		4,650		(13		)	4		(23,653	)	(26		)	16		(30,228	)	(52		)	13
Swing Swaps IFERC	69,145		—			2		87,253		(2		)	1		22,365		(4		)	2		54,158		12			—
Fixed Swaps/Futures	(1,784	)	1			1		(4,700	)	(1		)	2		2,323		1			—		(1,068	)	19			1
Forward Physical Contracts	(54,151	)	5			—		(145,105	)	6			41		(29,492	)	3			7		(123,254	)	(1		)	32
NGL (MBbls) – Forwards/Swaps	(4,997	)	(45		)	20		(2,493	)	5			16
NGLs (MBbls) – Forwards/Swaps															(9,687	)	50			46		(2,135	)	67			67
Refined Products (MBbls) – Futures															(906	)	(2		)	5		(1,403	)	(8		)	6
Crude (MBbls) – Forwards/Swaps	35,280		(190		)	152		9,172		(4		)	9		9,510		42			4		20,888		(60		)	29
Refined Products (MBbls) – Futures	(1,521	)	(5		)	9		(3,783	)	(25		)	4
Corn (thousand bushels)															(1,760	)	—			1		(1,920	)	—			1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	(4		)	—		(39,770	)	(2		)	—		(31,703	)	1			8		(17,445	)	(4		)	—
Fixed Swaps/Futures	(21,475	)	(2		)	7		(39,770	)	14			11		(31,703	)	14			8		(17,445	)	(10		)	6


⁽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~~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 instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Interest Rate Risk

As of September 30, ~~2018~~2019, we had ~~$4.88~~$3.76 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of ~~$49~~$38 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				Type⁽¹⁾	Notional Amount Outstanding
		September 30, 2018		December 31, 2017			September 30, 2019		December 31, 2018
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	$	—	$	300
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	400		300		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		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		—		Forward-starting to pay a fixed rate of 3.55% and receive a floating rate	400		400
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
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 based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300		Pay a floating rate and receive a fixed rate of 1.42%	—		300


⁽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.

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 ~~$239~~$362 million as of September 30, 2018. For the $1.50 billion of interest rate swaps whereby we pay a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $4 million.2019. 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 30, ~~2018~~2019 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act ~~(1)~~(i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and ~~(2)~~(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

~~There~~During the three months ended September 30, 2019, the Partnership, including certain of its subsidiaries, implemented an enterprise resource planning (“ERP”) system, in order to update existing technology and to integrate, simplify and standardize processes among the Partnership and its subsidiaries. Accordingly, we have made changes to our internal controls to address systems and/or processes impacted by the ERP implementation. Neither the ERP implementation nor the related control changes were undertaken in response to any deficiencies in the Partnership’s internal control over financial reporting.

Other than as discussed above, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)~~–15(f)~~-15(f) or Rule ~~15d–15(f)~~15d-15(f) of the Exchange Act) during the three months ended September 30, ~~2018~~2019 that 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 ~~23, 2018~~22, 2019 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 30, ~~2018.~~2019.

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 ~~January 18, 2018, PHMSA~~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 ~~Notice~~Permit Hold on any requests for approvals/permits or permit amendments made by us or any of ~~Probable Violation and~~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 ~~Proposed~~ Compliance Order ~~in connection with alleged violations~~related to impacts to streams and wetlands. The Partnership filed an appeal of the Streams and Wetlands Compliance Order on our Eastern Area refined products and crude oil pipeline system in the states of Michigan, Ohio, Pennsylvania, New York, New Jersey and Delaware. We have paid the civil penalties of $163,700. The case was closed in July 2018.

In June ~~2018,~~14, 2019. On August 5, 2019, ETC Northeast ~~Pipeline LLC (“ETC Northeast”) entered into~~and the Partnership received a ~~Consent Order~~Subpoena to Compel Documents and Agreement with the PADEP, pursuant to which ETC Northeast agreed to pay $150,242 to the PADEP to settle various statutory and common law claims relating to soil discharge into, and erosion of the stream bed of, Raccoon Creek in Center Township, Pennsylvania during construction of the Revolution Pipeline. ETC Northeast has paid the settlement amount and continues to monitor the construction site and work with the landowner to resolve any remaining issuesInformation related to the ~~restoration~~Revolution pipeline and the Incident. ETC Northeast and the Partnership filed an appeal of the ~~construction site.~~Subpoena on September 4, 2019.

On June ~~29, 2018, Luminant Energy Company, LLC~~4, 2019, the Oklahoma Corporation Commission’s (“~~Luminant”~~OCC”) filed informal and formal complaints against Energy Transfer Fuel, LP (“ETF”), with the Railroad Commission of Texas (“TRRC”). Luminant’s complaints allege that absent an agreement between Luminant and ETF regarding the rate to be charged for bundled transportation and storage service, ETF must file a statement of intent with the TRRC to change the rate charged to Luminant for this service. ETFTransportation Division filed a ~~response to Luminant’s informal~~ complaint on July 16, 2018. ETF filed a response and motion to dismiss Luminant’s formal complaint on July 23, 2018. On August 16, 2018, a Commission Administrative Law Judge (“ALJ”) granted ETF’s motion to dismiss Luminant’s claims relating to unlawful abandonment and discrimination. The ALJ denied ETF’s motion to dismiss Luminant’s claims regarding the rate charged for service and the procedural process applicable to rate changes. Luminant appealed the decision. The appeal was denied by operation of law on October 1, 2018. A mediation of the informal complaint filed by Luminant was held on September 17, 2018 and no decision was reached. The parties continue to negotiate in good faith.

On July 25, 2018, Energy Transfer Field Services received NOV REG-0569-1802 for emission events that occurred January 1, 2018 through April 30, 2018 at the Jal 3 gas plant. On September 25, 2018, the New Mexico Environmental Department sent ETP a settlement offer to resolve the NOV foragainst SPLP seeking a penalty of ~~$1,151,499. Negotiations for this settlement offer are ongoing.~~

~~On September 17,~~up to $1 million related to a May 2018 ~~William D. Warner (“Plaintiff”), a purported ETP unitholder, filed a putative class action asserting violations~~rupture near Edmond, Oklahoma. The rupture occurred on the Noble to Douglas 8” pipeline in an area of ~~various provisions~~external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the ~~Securities Exchange Act of 1934~~release and ~~various rules promulgated thereunder~~remediated the surrounding environment and pipeline in ~~connection~~cooperation with the ~~ETE-ETP Merger against ETP, Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff specifically alleges~~OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the ~~Form S-4 Registration Statement issued in connection~~pipeline causing the failure. SPLP is negotiating a settlement agreement with the ~~ETE-ETP Merger omits and/or misrepresents material information. Defendants believe the allegations have no merit and intend~~OCC for a lesser penalty.

For a description of other legal proceedings, see Note 10 to defend vigorously against them. On October 26, 2018, Plaintiff and Defendants entered into a stipulation staying Defendants’ response deadlines until the designation of a lead plaintiff/lead counsel structureour consolidated financial statements included in ~~accordance with the Private Securities Litigation Reform Act.~~“Item 1. Financial Statements.”

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 filed with the SEC on February 23, 2018 or 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, 2018 filed with the SEC on May 10, 2018 and “Part II - Item 1A. Risk Factors” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed on August 9, 2018.22, 2019.

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ITEM 6. EXHIBITS

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



Exhibit Number		Description
~~2.1~~3.1		Agreement and Plan of Merger, dated as of August 1, 2018, by and among LE GP, LLC, Energy Transfer Equity, L.P., Streamline Merger Sub, LLC, Energy Transfer Partners, L.L.C. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 to the Form 8-K filed August 3, 2018)
~~3.1~~		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1, ~~Registration Statement~~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		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)
3.5		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)
10.1***3.5.1		Amendment No. 1, dated as of December 31, 2018, to Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer ~~Partners, L.L.C. Annual Bonus Plan~~Operating, L.P. (incorporated by reference to Exhibit ~~10.3 of~~3.1 to the Current Report on Form ~~10-Q,~~8-K, File No. 1-31219, filed ~~August 9, 2018)~~January 4, 2019)
~~10.2~~3.5.2		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		Amendment No. 3, dated as of July 1, 2019, to ~~Five-Year~~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		Term Loan Credit ~~Agreement, Joinder and Increase and Extension~~ Agreement dated as of October ~~19, 2018, by and~~17, 2019 among Energy Transfer ~~Partners,~~Operating, L.P., ~~Sunoco Logistics Partners Operations L.P.,~~Toronto Dominion (Texas) LLC, as Administrative Agent, the other lenders party thereto and ~~Wells Fargo Bank, National Association, as administrative agent~~the other parties named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed October ~~19, 2018)~~18, 2019)
~~10.3~~10.2		~~Amendment No. 1 to 364-Day Credit Agreement, Joinder and Increase and Extension Agreement,~~Guaranty dated as of October ~~19, 2018, by and among Energy Transfer Partners, L.P.,~~17, 2019 between Sunoco Logistics Partners Operations L.P., and ~~Wells Fargo Bank, National Association,~~Toronto Dominion (Texas) LLC, as ~~administrative agent~~Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed October ~~19, 2018)~~18, 2019)
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.INS*		~~XBRL Instance Document~~
101.SCH*		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
104		Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)



*		Filed herewith.
**		Furnished herewith.
~~***~~		~~Denotes a management contract or compensatory plan or arrangement.~~

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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 ~~8, 2018~~7, 2019	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)

7278



PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets	1

Consolidated Statements of Operations	3

Consolidated Statements of Comprehensive Income	4

Consolidated ~~Statement~~Statements of Equity	5

Consolidated Statements of Cash Flows	6

~~Notes to Consolidated Financial Statements~~	7

Notes to Consolidated Financial Statements	8

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	4550

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	6773

ITEM 4. CONTROLS AND PROCEDURES	6975

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	7076

ITEM 1A. RISK FACTORS	7076

ITEM 6. EXHIBITS	7177

SIGNATURE	7278



	Three Months Ended September 30, 2017							Nine Months Ended September 30, 2017
	As Originally Reported		Effect of Change			As Adjusted		As Originally Reported		Effect of Change			As Adjusted
Cost of products sold	$	4,876	$	46		$	4,922	$	14,582	$	13		$	14,595
Operating income	825		(46		)	779		2,211		(13		)	2,198
Income before income tax expense (benefit)	649		(46		)	603		1,439		(13		)	1,426
Net income	761		(46		)	715		1,417		(13		)	1,404
Net income attributable to partners	651		(46		)	605		1,174		(36		)	1,138
Comprehensive income	768		(46		)	722		1,423		(13		)	1,410
Comprehensive income attributable to partners	658		(46		)	612		1,180		(36		)	1,144



	Three Months Ended September 30, 2018							Nine Months Ended September 30, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)			As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Revenues:
Natural gas sales	$	1,026	$	1,026	$	—		$	3,112	$	3,112	$	—
NGL sales	2,695		2,686		9			6,866		6,839		27
Crude sales	3,841		3,838		3			11,336		11,326		10
Gathering, transportation and other fees	1,579		1,783		(204		)	4,440		4,977		(537		)
Refined product sales	382		381		1			1,234		1,233		1
Other	118		118		—			343		343		—

Costs and expenses:
Cost of products sold	$	6,745	$	6,949	$	(204	)	$	19,873	$	20,410	$	(537	)
Operating expenses	632		619		13			1,863		1,825		38



	Sunoco LP		USAC		Lake Charles LNG and Other
Current assets	$	1,331	$	230	$	28
Property, plant and equipment, net	1,494		2,541		746
Goodwill	1,534		619		184
Intangible assets	655		399		35
Other non-current assets	134		25		909
Total assets	$	5,148	$	3,814	$	1,902

Current liabilities	$	1,086	$	173	$	107
Long-term debt, less current maturities	2,774		1,731		—
Other non-current liabilities	343		6		8
Preferred Units	—		477		—
Net assets	$	945	$	1,427	$	1,787



	Unaudited Pro Forma
	Nine Months Ended September 30,
	2018		2017
Revenues	$	40,514	$	29,072
Net income attributable to partners	$	2,282	$	1,138



	September 30, 2018			December 31, 2017
Available-for-sale securities ⁽¹⁾	$	6		$	8
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(7		)	(5		)
Investments in unconsolidated affiliates, net	14			5
Total AOCI, net of tax	$	8		$	3



	Years Ending December 31,
	2018 (remainder)		2019		2020		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2018	$	1,426	$	5,066	$	4,568	$	29,069	$	40,129



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2018		2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3	$	(5	)	$	36		$	21
Commodity derivatives – Non-trading	Cost of products sold	21		(12		)	(352		)	(15		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	45		(8		)	117			(28		)
Embedded derivatives	Other, net	—		—			—			1
Total		$	69	$	(25	)	$	(199	)	$	(21	)



	September 30, 2018		December 31, 2017
Long-term notes receivable from related company:
Sunoco LP	$	85	$	85



	Nine Months Ended September 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	20,444		$	—		$	20,444
Operating costs, expenses, and other	—		1			18,245			—			18,246
Operating income (loss)	—		(1		)	2,199			—			2,198
Interest expense, net	—		(113		)	(907		)	—			(1,020		)
Equity in earnings of unconsolidated affiliates	1,657		1,001			139			(2,658		)	139
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Other, net	—		4			134			(1		)	137
Income before income tax expense	1,657		891			1,537			(2,659		)	1,426
Income tax expense	—		—			22			—			22
Net income	1,657		891			1,515			(2,659		)	1,404
Less: Net income attributable to noncontrolling interest	—		—			266			—			266
Net income attributable to partners	$	1,657	$	891		$	1,249		$	(2,659	)	$	1,138

Other comprehensive income	$	—	$	—		$	6		$	—		$	6
Comprehensive income	1,657		891			1,521			(2,659		)	1,410
Comprehensive income attributable to noncontrolling interest	—		—			266			—			266
Comprehensive income attributable to partners	$	1,657	$	891		$	1,255		$	(2,659	)	$	1,144

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company