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, ~~2017~~2018



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

Commission file number 1-31219

ENERGY TRANSFER ~~PARTNERS,~~OPERATING, L.P.

(Exact name of registrant as specified in its charter)



Delaware		73-1493906
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

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

~~At November 3, 2017, the registrant had 1,155,493,524 Common Units outstanding.~~

FORM 10-Q

ENERGY TRANSFER ~~PARTNERS,~~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 ~~Partners,~~Operating, L.P. (the “Partnership” or “ETP”) 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~~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, ~~2016~~2017 filed with the Securities and Exchange Commission on February ~~24, 2017 and Exhibit 99.3 to~~23, 2018, “Part II – Item 1A. Risk Factors,” in the Partnership’s ~~Current~~Quarterly Report on Form ~~8-K~~10-Q for the quarter ended March 31, 2018 filed ~~with the Securities and Exchange Commission~~ on May ~~8, 2017.~~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.

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)

	~~AROs~~BBtu		~~asset retirement obligations~~billion British thermal units

	~~Bbls~~		~~barrels~~

	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

	~~CrossCountry~~		~~CrossCountry Energy, LLC~~

	DOJ		~~U.S.~~United States Department of Justice

	~~ETC Compression~~		~~ETC Compression, LLC~~

	EPA		United States Environmental Protection Agency

	~~ETC FEP~~		~~ETC Fayetteville Express Pipeline, LLC~~

	~~ETC MEP~~		~~ETC Midcontinent Express Pipeline, L.L.C.~~

	ETC OLP		La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company

	~~ETC Tiger~~		~~ETC Tiger Pipeline, LLC~~

	~~ETE~~		~~Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC for the periods presented herein~~

	~~ET Interstate~~		~~Energy Transfer Interstate Holdings, LLC~~

	~~ET Rover~~		~~ET Rover Pipeline LLC~~

	~~ETLP Credit Facility~~		~~Energy Transfer, LP’s $3.75 billion revolving credit facility~~

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

~~Table of Contents~~



	ETP Holdco		ETP Holdco Corporation

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

	Exchange Act		Securities Exchange Act of 1934

	~~ExxonMobil~~		~~Exxon Mobil Corporation~~

	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. ~~and its wholly-owned subsidiary, Regency Intrastate Gas LP~~

	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

	LIBOR		London Interbank Offered Rate

	~~MEP~~		~~Midcontinent Express Pipeline LLC~~

	MBbls		thousand barrels

	~~MMBtu~~MEP		~~million British thermal units~~

	~~MMcf~~		~~million cubic feet~~Midcontinent Express Pipeline LLC

	MTBE		methyl tertiary butyl ether

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

	NYMEX		New York Mercantile Exchange

	OSHA		federal Occupational Safety and Health Act

	OTC		over-the-counter

	Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries

	~~PCBs~~		~~polychlorinated biphenyls~~

	PennTex		PennTex Midstream Partners, LP

	PES		Philadelphia Energy Solutions ~~a refining joint venture~~

	~~Preferred Units~~		~~ETP Series A cumulative convertible preferred units~~

	Regency		Regency Energy Partners LP

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

	RIGS		Regency Intrastate Gas LP

	Rover		Rover Pipeline LLC, a subsidiary of ETP

	~~Sea Robin~~SEC		~~Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle~~Securities and Exchange Commission

	~~SEC~~Series A Preferred Units		~~Securities and Exchange Commission~~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		Sunoco Logistics Partners L.P.

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC, a subsidiary of Panhandle

	USAC		USA Compression Partners, LP

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 (excluding lower of cost or market adjustments).~~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 ~~PARTNERS,~~OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)


	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	379		$	360		$	379		$	306
Accounts receivable, net	3,083			3,002			3,671			3,946
Accounts receivable from related companies	335			209			333			318
Inventories	1,591			1,712			1,507			1,589
Income taxes receivable	151			128			169			135
Derivative assets	40			20			93			24
Other current assets	201			298			201			210
Total current assets	5,780			5,729			6,353			6,528

Property, plant and equipment	65,735			58,220			70,966			67,699
Accumulated depreciation and depletion	(8,763		)	(7,303		)	(10,416		)	(9,262		)
	56,972			50,917			60,550			58,437

Advances to and investments in unconsolidated affiliates	4,221			4,280			3,599			3,816
Other non-current assets, net	752			672			863			758
Intangible assets, net	5,379			4,696			4,925			5,311
Goodwill	3,907			3,897			2,866			3,115
Total assets	$	77,011		$	70,191		$	79,156		$	77,965

ENERGY TRANSFER ~~PARTNERS,~~OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)


	September 30, 2017		December 31, 2016		September 30, 2018		December 31, 2017
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,410	$	2,900	$	3,381	$	4,126
Accounts payable to related companies	204		43		287		209
Derivative liabilities	128		166		338		109
Accrued and other current liabilities	2,434		1,905		2,603		2,143
Current maturities of long-term debt	710		1,189		2,649		407
Total current liabilities	6,886		6,203		9,258		6,994

Long-term debt, less current maturities	33,630		31,741		31,198		32,687
Long-term notes payable – related company	—		250
Non-current derivative liabilities	132		76		57		145
Deferred income taxes	4,374		4,394		2,845		2,883
Other non-current liabilities	1,111		952		1,100		1,084

Commitments and contingencies
Preferred Units	—		33
Redeemable noncontrolling interests	21		15		22		21

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		—
Common Unitholders					25,628		26,531
General Partner	252		206		340		244
Limited Partners:
Common Unitholders	26,400		14,946
Class H Unitholder	—		3,480
Class I Unitholder	—		2
Accumulated other comprehensive income	14		8		8		3
Total partners’ capital	26,666		18,642		28,342		28,269
Noncontrolling interest	4,191		7,885		6,334		5,882
Total equity	30,857		26,527		34,676		34,151
Total liabilities and equity	$	77,011	$	70,191	$	79,156	$	77,965

ENERGY TRANSFER ~~PARTNERS,~~OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017*			2018			2017*
REVENUES:
Natural gas sales	$	1,098		$	1,069		$	3,132		$	2,602		$	1,026		$	1,098		$	3,112		$	3,132
NGL sales	1,750			1,249			4,782			3,339			2,695			1,750			6,866			4,782
Crude sales	2,273			1,649			6,751			4,572			3,841			2,381			11,336			7,268
Gathering, transportation and other fees	1,027			986			3,118			2,991			1,579			1,027			4,440			3,118
Refined product sales	334			177			1,109			656			382			334			1,234			1,109
Other	491			401			1,552			1,141			118			383			343			1,035
Total revenues	6,973			5,531			20,444			15,301			9,641			6,973			27,331			20,444
COSTS AND EXPENSES:
Cost of products sold	4,876			3,844			14,582			10,280			6,745			4,922			19,873			14,595
Operating expenses	571			475			1,603			1,359			632			571			1,863			1,603
Depreciation, depletion and amortization	596			503			1,713			1,469			636			596			1,827			1,713
Selling, general and administrative	105			71			335			226			123			105			347			335
Total costs and expenses	6,148			4,893			18,233			13,334			8,136			6,194			23,910			18,246
OPERATING INCOME	825			638			2,211			1,967			1,505			779			3,421			2,198
OTHER INCOME (EXPENSE):
Interest expense, net	(367		)	(345		)	(1,052		)	(981		)	(387		)	(352		)	(1,091		)	(1,020		)
Equity in earnings of unconsolidated affiliates	127			65			139			260			113			127			147			139
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
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	72			52			169			96			21			57			127			137
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	649			74			1,439			855			1,297			603			2,807			1,426
Income tax expense (benefit)	(112		)	(64		)	22			(131		)	(61		)	(112		)	(32		)	22
NET INCOME	761			138			1,417			986			1,358			715			2,839			1,404
Less: Net income attributable to noncontrolling interest	110			64			243			231			223			110			557			266
NET INCOME ATTRIBUTABLE TO PARTNERS	651			74			1,174			755			$	1,135		$	605		$	2,282		$	1,138
General Partner’s interest in net income	270			220			727			740
Class H Unitholder’s interest in net income	—			93			98			257
Class I Unitholder’s interest in net income	—			2			—			6
Common Unitholders’ interest in net income (loss)	$	381		$	(241	)	$	349		$	(248	)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$	0.33		$	(0.33	)	$	0.35		$	(0.36	)
Diluted	$	0.33		$	(0.33	)	$	0.34		$	(0.36	)

* As adjusted. See Note 1.

ENERGY TRANSFER ~~PARTNERS,~~OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,						Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016			2018		2017*		2018			2017*
Net income	$	761	$	138	$	1,417		$	986		$	1,358	$	715	$	2,839		$	1,404
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2		—		5			5			2		2		—			5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	5		—		2			(3		)	—		5		(2		)	2
Foreign currency translation adjustments	—		—		—			(1		)
Change in other comprehensive income from unconsolidated affiliates	—		2		(1		)	(9		)	2		—		9			(1		)
	7		2		6			(8		)	4		7		7			6
Comprehensive income	768		140		1,423			978			1,362		722		2,846			1,410
Less: Comprehensive income attributable to noncontrolling interest	110		64		243			231			223		110		557			266
Comprehensive income attributable to partners	$	658	$	76	$	1,180		$	747		$	1,139	$	612	$	2,289		$	1,144

* As adjusted. See Note 1.

ENERGY TRANSFER ~~PARTNERS,~~OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, ~~2017~~2018

(Dollars in millions)

(unaudited)


				Limited Partners																	Limited Partners
	General Partner			Common Units			Class H Units			Class I Units			Accumulated Other Comprehensive Income		Noncontrolling Interest			Total			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, 2016	$	206		$	14,946		$	3,480		$	2		$	8	$	7,885		$	26,527
Balance, December 31, 2017																					$	944		$	547		$	—		$	—		$	26,531		$	244		$	3		$	5,882		$	34,151
Distributions to partners	(681		)	(1,765		)	(95		)	(2		)	—		—			(2,543		)	(44		)	(27		)	(10		)	—			(1,975		)	(1,080		)	—			—			(3,136		)
Distributions to noncontrolling interest	—			—			—			—			—		(306		)	(306		)	—			—			—			—			—			—			—			(536		)	(536		)
Units issued for cash	—			2,162			—			—			—		—			2,162			—			—			436			431			58			—			—			—			925
Sunoco Logistics Merger	—			9,459			(3,483		)	—			—		(5,976		)	—
Capital contributions from noncontrolling interest	—			—			—			—			—		1,907			1,907			—			—			—			—			—			—			—			438			438
Sale of Bakken Pipeline interest	—			1,260			—			—			—		740			2,000
Acquisition of PennTex noncontrolling interest	—			(48		)	—			—			—		(232		)	(280		)
Repurchases of common units																					—			—			—			—			(24		)	—			—			—			(24		)
Other comprehensive income, net of tax	—			—			—			—			6		—			6			—			—			—			—			—			—			7			—			7
Other, net	—			37			—			—			—		(70		)	(33		)	(1		)	—			(1		)	(1		)	41			(17		)	(2		)	(7		)	12
Net income	727			349			98			—			—		243			1,417			45			27			14			6			997			1,193			—			557			2,839
Balance, September 30, 2017	$	252		$	26,400		$	—		$	—		$	14	$	4,191		$	30,857
Balance, September 30, 2018																					$	944		$	547		$	439		$	436		$	25,628		$	340		$	8		$	6,334		$	34,676

ENERGY TRANSFER ~~PARTNERS,~~OPERATING, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2018			2017*
OPERATING ACTIVITIES
Net income	$	1,417		$	986		$	2,839		$	1,404
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,713			1,469			1,827			1,713
Deferred income taxes	(1		)	(154		)	(17		)	(1		)
Amortization included in interest expense	5			(16		)
Inventory valuation adjustments	(30		)	(143		)
Unit-based compensation expense	57			60
Impairment of investment in an unconsolidated affiliate	—			308
Non-cash compensation expense							61			57
Gain on Sunoco LP common unit repurchase							(172		)	—
Loss on deconsolidation of CDM							86			—
Distributions on unvested awards	(21		)	(19		)	(24		)	(21		)
Equity in earnings of unconsolidated affiliates	(139		)	(260		)	(147		)	(139		)
Distributions from unconsolidated affiliates	319			292			328			319
Other non-cash	(168		)	(230		)	(132		)	(163		)
Net change in operating assets and liabilities, net of effects of acquisition	185			172
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations							451			168
Net cash provided by operating activities	3,337			2,465			5,100			3,337
INVESTING ACTIVITIES
Proceeds from Bakken Pipeline Transaction	2,000			—
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction	—			2,200
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		)	—			—			(280		)
Cash paid for all other acquisitions	(264		)	(159		)	(29		)	(264		)
Capital expenditures, excluding allowance for equity funds used during construction	(6,074		)	(5,787		)	(4,962		)	(6,074		)
Contributions in aid of construction costs	18			44			95			18
Contributions to unconsolidated affiliates	(230		)	(47		)	(13		)	(230		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	116			112			62			116
Proceeds from the sale of assets	33			6			13			33
Change in restricted cash	—			(8		)
Other	(6		)	(1		)	—			(6		)
Net cash used in investing activities	(4,687		)	(3,640		)	(3,067		)	(4,687		)
FINANCING ACTIVITIES
Proceeds from borrowings	19,978			13,073			16,930			19,978
Repayments of long-term debt	(18,487		)	(11,308		)
Repayments of debt							(16,520		)	(18,487		)
Cash paid to affiliate notes	(255		)	(1		)	—			(255		)
Units issued for cash	2,162			794
Subsidiary units issued for cash	—			1,305
Common units issued for cash							58			2,162
Preferred units issued for cash							867			—
Capital contributions from noncontrolling interest	919			187			438			919
Distributions to partners	(2,543		)	(2,669		)	(3,136		)	(2,543		)
Distributions to noncontrolling interest	(306		)	(334		)	(536		)	(306		)
Redemption of Preferred Units	(53		)	—
Repurchases of common units							(24		)	—
Redemption of Legacy ETP Preferred Units							—			(53		)
Debt issuance costs	(50		)	(22		)	(42		)	(50		)
Other	4			—			5			4
Net cash provided by financing activities	1,369			1,025
Increase (decrease) in cash and cash equivalents	19			(150		)
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	360			527			306			360
Cash and cash equivalents, end of period	$	379		$	377		$	379		$	379

* As adjusted. See Note 1.

ENERGY TRANSFER ~~PARTNERS,~~OPERATING, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts ~~except per unit data,~~ are in millions)

(unaudited)


1.	ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer ~~Partners,~~Operating, L.P. ~~(“ETP”, formerly named “Sunoco Logistics Partners L.P.”, as discussed below)~~ is a consolidated subsidiary of ~~ETE.~~ Energy Transfer LP. 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 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.

Following the closing of the ETE-ETP Merger, ETE changed its name to “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. prior to the close 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 ~~(the “Sunoco Logistics Merger”)~~ in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit ~~transaction. Prior to~~transaction (the “Sunoco Logistics Merger”), with the ~~Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of~~ Energy Transfer Partners, L.P. ~~Under the terms of the transaction, the~~ unitholders ~~received~~receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. ~~Under~~In connection with the ~~terms of the merger agreement,~~Sunoco Logistics Merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.

At the time of the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:

~~References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;~~

~~References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and~~

~~References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.~~

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 legal and reporting perspective. Therefore, for the pre-merger periods, 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.” prior to the ~~merger and name changes).~~

~~The~~ Sunoco Logistics Merger ~~was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets~~ and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.

The historical common units and net income (loss) per limited partner 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.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, ~~Denver~~Colorado and Ohio.

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ETEnergy Transfer Interstate Holdings, LLC, (“ETIH”) with revenues consisting primarily of fees earned from natural gas transportation services and operational gas ~~sales. ET Interstate~~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 ~~FEP,~~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 ~~MEP,~~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. ~~owned and operated retail marketing assets, which were contributed to Sunoco LP in March 2016. Subsequent to this transaction, Sunoco Inc.~~’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. ~~Subsequent to the Sunoco Logistics Merger, ETLP~~ETP Holdco also holds an equity method investment in ETP through ~~ETP Holdco’s~~its ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in ~~the~~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.

~~Subsequent to the Sunoco Logistics Merger, our~~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; 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, L.P. for the year ended December 31, ~~2016,~~2017, included in ~~Exhibit 99.1 to~~ the Partnership’s ~~Current~~Annual Report on Form ~~8-K~~10-K filed with the SEC on ~~August 14, 2017.~~February 23, 2018. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.

~~Use of Estimates~~

The ~~unaudited~~historical common unit amounts presented in these consolidated financial statements have been ~~prepared~~retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in ~~conformity~~connection with ~~GAAP, which includes~~ the ~~use~~Sunoco Logistics Merger.

Change in Accounting Policy

Inventory Accounting Change

During the fourth quarter of ~~estimates~~2017, the Partnership elected 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 ~~assumptions made by management~~NGLs associated with the legacy Sunoco Logistics business. Management believes that ~~affect~~ the ~~reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at~~weighted-average cost method is preferable to the ~~date of~~LIFO method as it more closely aligns the accounting policies across the consolidated ~~financial statements. Although~~entity.

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~~these estimates are based on management’s available knowledge~~As a result of ~~current~~this change in accounting policy, the consolidated statement of operations and ~~expected future events, actual results could be different from those estimates.~~comprehensive income in prior periods have been retrospectively adjusted, as follows:

~~Recent Accounting Pronouncements~~

~~ASU 2014-09~~



	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 ~~expects to adopt~~adopted ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard.on January 1, 2018.

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements.

We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of our reportable segments as well as the accounting for certain processing contracts in our midstream segment. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.

~~We are still evaluating the potential impact of~~Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to ~~contributions~~decreases in ~~aid~~revenue (with offsetting decreases to cost of ~~construction costs (“CIAC”) arrangements~~sales) resulting from recognition of non-cash consideration as revenue when received and ~~materiality~~as cost of ~~any~~sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related ~~changes. While we do not expect any impacts~~ to ~~net income from~~multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the ~~application of the standard to other transactions,~~evaluation performed, we have ~~not concluded whether the application of the standard to CIAC transactions could impact net income.~~

~~We continue to assess the impact of the disclosure requirements under the new standard~~made appropriate design and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. In addition, we are in the process of implementing appropriate changesimplementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. ~~We continue~~

Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to ~~monitor additional authoritative or interpretive guidance related~~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 ~~as it becomes~~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.

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 ~~as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.~~knowledge of current and expected future events, actual results could be different from those estimates.

Recent Accounting Pronouncements

ASU 2016-02

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report ~~useful~~ information ~~to users of financial statements~~ about the amount, timing, and uncertainty of cash flows arising from a lease. ~~ASU 2016-02 is effective for fiscal years beginning after December 15, 2018,~~The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

~~ASU 2016-09~~

~~On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09,~~ ~~Stock Compensation (Topic 718)~~ ~~(“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of~~ the accounting for ~~employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities,~~sales-type and ~~classification on the statement of cash flows. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements and related disclosures.~~

~~ASU 2016-16~~

direct financing leases. In ~~October 2016,~~January 2018, the FASB issued Accounting Standards Update No. ~~2016-16,~~ ~~Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory~~2018-01 (“ASU ~~2016-16”~~2018-01”), which ~~requires that entities recognize the income tax consequences of~~provides an ~~intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do~~optional transition practical expedient to not ~~change GAAP for the pre-tax effects of an intra-entity asset transfer~~evaluate under Topic ~~810, Consolidation,~~842 existing or expired land easements that were not previously accounted for ~~an intra-entity transfer~~as leases under the existing lease guidance in Topic 840. The Partnership plans to elect the package of ~~inventory. ASU 2016-16 is effective~~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 standard 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 ~~fiscal years beginning after December 15, 2017,~~our leases in accordance with the new standard. However, we are still in the process of quantifying this impact. We expect that upon adoption most of the Partnership’s lease commitments will be recognized as right of use assets and ~~interim periods within those~~lease obligations.

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annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.

~~ASU 2016-17~~

~~On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17,~~ ~~Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control~~ (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.

~~ASU 2017-04~~

~~In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.~~” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ~~ASU~~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. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements 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 a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts 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.


2.	ACQUISITIONS AND ~~CONTRIBUTION~~OTHER INVESTING TRANSACTIONS

~~Rover~~ETE Contribution ~~Agreement~~of Assets to ETP

~~In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for~~Immediately prior to the ~~purchase by Blackstone of a 49.9% interest in the holding company that owns 65%~~closing of the ~~Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone~~ETE-ETP Merger discussed in Note 1, ETE contributed the following to ~~contribute, at closing, funds~~ETP:

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

100 percent of the ~~Rover construction costs incurred by ETP through~~limited liability company interests in Sunoco GP LLC, the ~~closing date, along with the payment~~sole general partner of ~~additional amounts subject to certain adjustments. The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP~~Sunoco LP, and ~~49.9% by Blackstone.~~

~~Permian Express Partners~~

In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.

In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in the Partnership’s ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the ~~assets. As such, PEP is reflected~~IDRs in Sunoco LP, to ETP in exchange for 42,812,389 ETP common units;

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 ~~subsidiary~~financial statements will be retrospectively adjusted to reflect consolidation of ~~the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an~~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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~~increase~~The following table summarizes the assets and liabilities of ~~$988~~Sunoco LP, USAC and Lake Charles LNG and Other as of 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:



	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 ~~in noncontrolling interest,~~, which is reflected in ~~“Capital contributions~~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 ~~noncontrolling interest”~~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 ~~statement~~subsidiary.

USAC

As of ~~equity.~~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.


3.4.	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.

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


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2018			2017*
Accounts receivable	$	(77	)	$	(595	)	$	251		$	(77	)
Accounts receivable from related companies	46			80			206			46
Inventories	150			(299		)	48			133
Other current assets	37			(135		)	(23		)	37
Other non-current assets, net	(89		)	(1		)	(99		)	(89		)
Accounts payable	96			635			(177		)	96
Accounts payable to related companies	(11		)	24			(199		)	(11		)
Accrued and other current liabilities	(26		)	213			351			(26		)
Other non-current liabilities	57			31			21			57
Derivative assets and liabilities, net	2			219			72			2
Net change in operating assets and liabilities, net of effects of acquisitions	$	185		$	172
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,				Nine Months Ended September 30,
	2017		2016		2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,236	$	991	$	1,026	$	1,236
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	—		194
Net gains from subsidiary common unit issuances	—		34
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	$	—	$	—	$	988

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4.5.	INVENTORIES

Inventories consisted of the following:


	September 30, 2017		December 31, 2016		September 30, 2018		December 31, 2017
Natural gas and NGLs	$	609	$	699
Natural gas, NGLs and refined products					$	615	$	733
Crude oil	696		683		643		551
Refined products	69		113
Spare parts and other	217		217		249		305
Total inventories	$	1,591	$	1,712	$	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.


5.6.	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, ~~2017 were $35.89~~2018 was $34.39 billion and ~~$34.34~~$33.85 billion, respectively. As of December 31, ~~2016,~~2017, the aggregate fair value and carrying amount of

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our consolidated debt obligations ~~were $33.85~~was $34.28 billion and ~~$32.93~~$33.09 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, ~~2017,~~2018, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, ~~2017~~2018 and December 31, ~~2016~~2017 based on inputs used to derive their fair values:


				Fair Value Measurements at September 30, 2017									Fair Value Measurements at September 30, 2018
	Fair Value Total			Level 1			Level 2			Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	16		$	16		$	—		$	48		$	48		$	—
Swing Swaps IFERC	2			—			2			1			—			1
Fixed Swaps/Futures	28			28			—			25			25			—
Forward Physical Swaps	3			—			3
Forward Physical Contracts										12			—			12
Power:
Forwards	11			—			11			36			—			36
Futures	1			1			—
Options – Puts	1			1			—			1			1			—
Natural Gas Liquids – Forwards/Swaps	213			213			—
Refined Products – Futures	2			2			—
Crude – Futures	2			2			—
NGLs – Forwards/Swaps										476			476			—
Total commodity derivatives	279			263			16			599			550			49
Other non-current assets										28			18			10
Total assets	$	279		$	263		$	16		$	627		$	568		$	59
Liabilities:
Interest rate derivatives	$	(210	)	$	—		$	(210	)	$	(97	)	$	—		$	(97	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(22		)	(22		)	—			(89		)	(89		)	—
Swing Swaps IFERC	(3		)	(1		)	(2		)	(1		)	—			(1		)
Fixed Swaps/Futures	(22		)	(22		)	—			(26		)	(26		)	—
Forward Physical Swaps	(1		)	—			(1		)
Forward Physical Contracts										(7		)	—			(7		)
Power:
Forwards	(9		)	—			(9		)	(30		)	—			(30		)
Futures	(1		)	(1		)	—			(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(261		)	(261		)	—
NGLs – Forwards/Swaps										(521		)	(521		)	—
Refined Products – Futures	(2		)	(2		)	—			(5		)	(5		)	—
Crude – Futures	(1		)	(1		)	—
Crude – Forwards/Swaps										(190		)	(190		)	—
Total commodity derivatives	(322		)	(310		)	(12		)	(870		)	(832		)	(38		)
Total liabilities	$	(532	)	$	(310	)	$	(222	)	$	(967	)	$	(832	)	$	(135	)

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Fair Value Measurements at
December 31, 2016
Fair Value Total Level 1 Level 2 Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX $ 14
$ 14
$ —
$ —
Swing Swaps IFERC 2
—
2
—
Fixed Swaps/Futures 96
96
—
—
Forward Physical Swaps 1
—
1
—
Power:

Forwards 4
—
4
—
Futures 1
1
—
—
Options – Calls 1
1
—
—
Natural Gas Liquids – Forwards/Swaps 233
233
—
—
Refined Products – Futures 1
1
—
—
Crude – Futures 9
9
—
—
Total commodity derivatives 362
355
7
—
Total assets $ 362
$ 355
$ 7
$ —
Liabilities:
Interest rate derivatives $ (193 ) $ —
$ (193 ) $ —
Embedded derivatives in Preferred Units (1 ) —
—
(1 )
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX (11 ) (11 ) —
—
Swing Swaps IFERC (3 ) —
(3 ) —
Fixed Swaps/Futures (149 ) (149 ) —
—
Power:

Forwards (5 ) —
(5 ) —
Futures (1 ) (1 ) —
—
Natural Gas Liquids – Forwards/Swaps (273 ) (273 ) —
—
Refined Products – Futures (17 ) (17 ) —
—
Crude – Futures (13 ) (13 ) —
—
Total commodity derivatives (472 ) (464 ) (8 ) —
Total liabilities $ (666 ) $ (464 ) $ (201 ) $ (1 )


6.	~~NET INCOME (LOSS) PER LIMITED PARTNER UNIT~~

Net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to the General Partner, the holder of the IDRs pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net income $ 761
$ 138
$ 1,417
$ 986
Less: Income attributable to noncontrolling interest 110
64
243
231
Net income, net of noncontrolling interest 651
74
1,174
755
General Partner’s interest in net income 270
220
727
740
Class H Unitholder’s interest in net income —
93
98
257
Class I Unitholder’s interest in net income —
2
—
6
Common Unitholders’ interest in net income (loss) 381
(241 ) 349
(248 )
Additional (earnings) distributions allocated to General Partner —
(3 ) 12
(9 )
Distributions on employee unit awards, net of allocation to General Partner (6 ) (5 ) (19 ) (15 )
Net income (loss) available to Common Unitholders $ 375
$ (249 ) $ 342
$ (272 )
Weighted average Common Units – basic ⁽¹⁾
1,125.2
761.1
990.9
749.7
Basic net income (loss) per Common Unit $ 0.33
$ (0.33 ) $ 0.35
$ (0.36 )

Dilutive effect of unvested employee unit awards 3.7
—
4.6
—
Weighted average Common Units – diluted ⁽¹⁾
1,128.9
761.1
995.5
749.7
Diluted net income (loss) per Common Unit $ 0.33
$ (0.33 ) $ 0.34
$ (0.36 )

⁽¹⁾~~Excludes Common Units owned by the Partnership’s consolidated subsidiaries.~~

For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.



				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.	DEBT OBLIGATIONS

ETP Senior Notes Offering and Redemption

In ~~October 2017,~~June 2018, ETP issued the ~~Partnership redeemed all of the outstanding $500~~following senior notes:

•$500 million aggregate principal amount of ~~ETLP’s 6.50%~~4.20% senior notes due ~~July 2021 and all~~2023;

•$1.00 billion aggregate principal amount of ~~the outstanding $700~~4.95% senior notes due 2028;

•$500 million aggregate principal amount of ~~ETLP’s 5.50%~~5.80% senior notes due ~~April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.~~

~~ETP Senior Notes Offering~~ 2038; and

~~In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50~~•$1.00 billion aggregate principal amount of ~~5.40%~~6.00% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility (described below) and for general partnership purposes.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 ~~is payable upon maturity. Interest~~ on the senior notes is payable upon maturity and interest is paid semi-annually.

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The senior notes are guaranteed by the parent company (ETP) on a senior unsecured basis as long as it guarantees any of Sunoco Logistics Partners Operations L.P.’s other long-term debt. As a result of the parent guarantee, the senior notes will rank equally in right of payment with ~~the Partnership’s~~ETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt ~~the Partnership~~ETP 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 $2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETP’s revolving credit facility, for general partnership purposes and to redeem all of the following senior notes:

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

~~Table~~•Panhandle’s $400 million aggregate principal amount of ~~Contents~~

7.00% senior notes due June 15, 2018; and

•ETP’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018.

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

Credit Facilities and Commercial Paper

~~ETLP~~ETP Five-Year Credit Facility

The ETLP Credit Facility allows for borrowings of up to $3.75 billion and matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of which was commercial paper.

~~Sunoco Logistics Credit Facilities~~

~~ETP maintains the Sunoco Logistics $2.50 billion unsecured~~ETP’s revolving credit facility (the ~~“Sunoco Logistics~~“ETP Five-Year Credit Facility”)~~, which matures~~ previously allowed for unsecured borrowings up to $4.00 billion and matured in ~~March 2020.~~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 December 1, 2023. The ~~Sunoco Logistics~~ETP Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to ~~$3.25~~$6.00 billion under certain conditions.

As of September 30, ~~2017,~~2018, the ~~Sunoco Logistics~~ETP Five-Year Credit Facility had ~~$35~~$1.78 billion outstanding, of which $1.57 billion was commercial paper. The amount available for future borrowings was $2.06 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. The weighted average interest rate on the total amount outstanding as of ~~outstanding borrowings.~~September 30, 2018 was 3.00%.

ETP 364-Day Facility

~~In December 2016, Sunoco Logistics entered into an agreement for a~~ETP’s 364-day ~~maturity~~revolving credit facility (“(the “ETP 364-Day ~~Credit~~ Facility”)~~, due~~ previously allowed for unsecured borrowings up to ~~mature~~$1.00 billion and matured on November 30, 2018. On October 19, 2018, the ~~earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the~~ETP 364-Day ~~Credit~~ Facility was ~~terminated and repaid in May 2017.~~amended to extend the maturity date to November 29, 2019. As of September 30, 2018, the ETP 364-Day Facility had no outstanding borrowings.

Bakken Credit Facility

In August 2016, ~~Energy Transfer Partners, L.P., Sunoco Logistics~~ETP and Phillips 66 completed project-level financing of the Bakken ~~Pipeline.~~pipeline. The $2.50 billion credit facility ~~provides substantially all of the remaining capital necessary to complete the projects.~~matures in August 2019 (the “Bakken Credit Facility”). As of September 30, ~~2017,~~2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings, all of which has been reflected in current maturities of long-term debt on the Partnership’s consolidated balance sheet. The weighted average interest rate on the total amount outstanding as of September 30, 2018 was ~~outstanding under this credit facility.~~

~~PennTex Revolving Credit Facility~~

~~PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”)~~3.85%. ~~In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.~~

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, ~~2017.~~2018.

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8.	~~PREFERRED UNITS~~

~~In January 2017, Energy Transfer Partners, L.P. repurchased all of its 1.9 million outstanding Preferred Units for cash in the aggregate amount of $53 million.~~


9.	EQUITY

The changes in outstanding common units during the nine months ended September 30, ~~2017~~2018 were as follows:



	Number of Units
Number of common units at December 31, ~~2016~~ ⁽¹⁾ 2017	~~794.8~~
~~Common Units issued in connection with public offerings~~	~~54.0~~
~~Common units issued in connection with equity distribution agreements~~	~~22.6~~1,164.1
Common units issued in connection with the distribution reinvestment plan	~~4.6~~2.9
Common units issued ~~to ETE~~ in ~~a private placement transaction~~connection with certain transactions	~~23.7~~
~~Common unit increase from Sunoco Logistics Merger~~ ⁽²⁾	~~255.4~~1.3
Issuance of common units under equity incentive plans	~~0.4~~0.1
Repurchases of common units in open-market transactions	(1.2	)
Number of common units at September 30, ~~2017~~2018	~~1,155.5~~1,167.2


⁽¹⁾	~~The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange~~ Subsequent to the ETE-ETP Merger in October 2018, all of the outstanding ETP common units are held directly or indirectly by ETE, including the ETP common units issued in ~~connection with the Sunoco Logistics Merger.~~

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⁽²⁾	~~Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.~~

In connection with the ~~Sunoco Logistics Merger,~~conversion of the ~~previous Energy Transfer Partners, L.P. equity distribution agreement was terminated.~~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 ~~May 2017,~~addition, the ~~Partnership entered into an equity distribution agreement~~ETP Class I units and Class J units were also cancelled in connection with ~~an aggregate offering price up to $1.00 billion.~~ the ETE-ETP Merger.

Equity Distribution Program

During the nine months ended September 30, ~~2017,~~2018, there were no units issued under the ~~Partnership received proceeds of $498 million, net of $5 million of commissions, from the issuance of common units pursuant to~~Partnership’s equity distribution ~~agreements, which were used for general partnership purposes.~~

agreement. In connection with the ~~Sunoco Logistics~~ETE-ETP Merger, the ~~previous Energy Transfer Partners, L.P.~~equity distribution ~~reinvestment plan~~program was ~~terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan.~~ terminated in October 2018.

Distribution Reinvestment Program

During the nine months ended September 30, ~~2017,~~2018, distributions of ~~$106~~$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.

~~August~~Preferred Units

ETP issued 950,000 Series A Preferred Units and 550,000 Series B Preferred Units in November 2017 ~~Units Offering~~

~~In August 2017, the Partnership~~and has issued ~~54 million ETP common~~additional preferred units in ~~an underwritten public offering. Net~~2018, as discussed below. Subsequent to the ETE-ETP Merger, all of ETP’s Series A, Series B, Series C and Series D Preferred Units remain outstanding.

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 proceeds of ~~$997 million from the offering~~$450 million. The proceeds were used ~~by the Partnership~~ to repay amounts outstanding under ~~its~~ETP’s revolving credit ~~facilities, to fund capital expenditures~~facility and for general partnership purposes.

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

~~Bakken Equity Sale~~Series D Preferred Units Issuance

In February 2017, Bakken Holdings Company LLC, an entity in which the Partnership indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July ~~2017, the Partnership contributed a portion~~2018, ETP issued 17.8 million of its ~~ownership interest~~7.625% Series D Preferred Units at a price of $25 per unit, resulting in ~~Dakota Access~~total gross proceeds of $445 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and ~~ETCO~~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, ~~PEP,~~but excluding, August 15, 2023, at a ~~strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.~~

~~PennTex Tender Offer and Limited Call Right Exercise~~

~~In June 2017, ETP purchased all~~rate of 7.625% per annum of the ~~outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all~~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 ~~economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.~~

~~Quarterly Distributions of Available Cash~~

Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the Partnership’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prior$25 liquidation preference equal to ~~the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end~~an annual floating rate of the ~~quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement.~~three-month LIBOR, determined quarterly, plus a spread of 4.378% per annum. The ~~general partner has broad discretion to establish cash reserves that it determines~~Series D Preferred Units are ~~necessary~~redeemable at ETP’s option on or ~~appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations~~ after ~~establishment~~August 15, 2023 at a redemption price of ~~cash reserves and payment of fees and expenses, including payments to the general partner.~~

~~If cash distributions exceed $0.0833~~$25 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.Series D

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~~The following table shows~~Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the ~~target distribution levels~~date of redemption.

Cash Distributions

Distributions on common units declared and ~~distribution “splits” between~~paid by the ~~general partner and~~Partnership subsequent to December 31, 2017 but prior to the ~~holders~~closing of the ~~Partnership’s common units:~~ETE-ETP Merger as discussed in Note 1 were as follows:

Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target Amount IDRs
Partners ⁽¹⁾
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%



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

⁽¹⁾ ~~Includes general partner and limited partner interests, based~~Distributions on ~~the proportionate ownership of each.~~

~~For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.~~

~~Following are distributions~~ETP’s preferred units declared and/or paid by the Partnership subsequent to ~~the Sunoco Logistics Merger:~~December 31, 2017 were as follows:

Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 15, 2017 $ 0.5350
June 30, 2017 August 7, 2017 August 14, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650

~~ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods.~~

Total Year
2017 (remainder) $ 173
2018 153
2019 128
Each year beyond 2019 33



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

Accumulated Other Comprehensive Income

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


	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
Available-for-sale securities(1)	$	7		$	2		$	6		$	8
Foreign currency translation adjustment	(5		)	(5		)	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	9			7
Actuarial loss related to pensions and other postretirement benefits							(7		)	(5		)
Investments in unconsolidated affiliates, net	3			4			14			5
Total AOCI, net of tax	$	14		$	8		$	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.


~~10.~~9.	INCOME TAXES

~~For the nine months ended September 30, 2017, the~~The Partnership’s ~~income~~effective tax ~~expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting~~rate differs from the ~~Sunoco Logistics Merger in April 2017, which resulted in incremental~~statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income ~~tax expense of approximately $68 million during~~taxes at the ~~period. In addition, for~~partnership level. For the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. The three and nine months ended September 30, ~~2017 also reflect increased~~2018, the Partnership’s income tax ~~expense due to higher earnings among~~benefit also reflected $109 million and $179 million, respectively, of deferred benefit adjustments as the ~~Partnership’s consolidated corporate subsidiaries. For~~result of a state statutory rate reduction.

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 2004 through 2011 years, Sunoco, Inc. filed amended returns with the ~~three and nine months ended September~~Internal

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~~30,~~Revenue Service (“IRS”) excluding these government incentive payments from federal taxable income. The IRS denied the amended returns and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the ~~Partnership’s income tax benefit primarily resulted from losses among~~CFC ruled against Sunoco, Inc., and the ~~Partnership’s consolidated corporate subsidiaries.~~Federal Circuit affirmed the CFC’s ruling on November 1, 2018. Sunoco, Inc. is considering seeking further review of this decision. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims.


~~11.~~10.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

~~Contingent Residual Support Agreement – AmeriGas~~

In connection with the closing of the contribution of its propane operations in January 2012, ETLP (formerly Energy Transfer Partners, L.P.) agreed to provide contingent residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETLP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its 7.00% senior notes. The remaining outstanding 7.00% senior notes were repurchased in May 2017, and ETLP no longer provides contingent residual support for any AmeriGas notes.

Guarantee of Sunoco LP Notes

In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to ~~(i) $800 million principal amount~~certain of ~~6.375%~~Sunoco LP’s senior notes ~~due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP~~ and ~~(iii)~~ $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.~~ LLC (“ETC M-A”).

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.

FERC Audit

In March 2016, the FERC commenced an audit of Trunkline for 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 as prescribed by the FERC, and the FERC’s annual reporting requirements. The FERC approved an audit ~~is ongoing.~~ 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 does not expect the findings to result in any changes to its financial statements.

Commitments

In the normal course of ~~our~~ business, ~~we purchase, process~~ETP purchases, processes and ~~sell~~sells natural gas pursuant to long-term contracts and ~~we enter~~enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ~~We believe~~ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on ~~our~~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, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Rental expense $ 29
$ 19
$ 68
$ 58



	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

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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 ~~U.S.~~United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access, ~~consistent with environmental and historic preservation statutes for the pipeline~~LLC (“Dakota Access”) to make two crossings of the Missouri River in North ~~Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the~~Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri ~~River in two locations. Also in~~River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the ~~U.S.~~United States District Court for the District of Columbia (“the Court”) against the USACE ~~that~~and challenged the legality of ~~the~~these permits ~~issued for the construction of the Dakota Access pipeline across those waterways~~ 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 ~~is pending.~~was pending, which the court denied on September 9, 2016. Dakota Access intervened in the case. The SRST soon added a request for an emergency TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the temporary restraining orderCheyenne River Sioux Tribe (“~~TRO”~~CRST”) ~~request moot.~~

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion.also intervened. The SRST filed an amended complaint and added claims based on treaties between the ~~tribes~~SRST and the CRST and the United States and statutes governing the use of government property.

~~In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe.~~ In February 2017, in response to a presidential memorandum, the Department of the Army ~~decided that no further environmental review was necessary and~~ delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. ~~Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016,~~The CRST moved for a preliminary injunction and ~~TRO~~temporary restraining order (“TRO”) to block operation of the ~~pipeline. These motions~~pipeline, which was denied, and raised ~~for the first time,~~ claims based on the religious rights of the Tribe. The district court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.CRST.

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala 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.~~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 ~~rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court~~ concluded that the USACE had not violated ~~any~~ 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 ~~determination~~determinations under certain of these statutes. ~~The~~On May 3, 2018, the District Court ordered ~~briefing~~the USACE to ~~determine whether~~file a status report by June 8, 2018 informing the ~~pipeline should remain in operation during~~Court when the ~~pendency of~~USACE expects the ~~USACE’s review~~remand process ~~or whether~~ to ~~vacate~~be complete. On June 8, 2018, the ~~existing permits.~~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 ~~and Dakota Access opposed any shutdown~~indicated that a document detailing its remand analysis would be filed after a “confidentiality review.” Following the submission by USACE of ~~operations~~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 ~~this~~the remand process. First, Dakota Access must retain an independent third-party to review ~~process. On October 11,~~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 ~~issued~~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 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 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 seek an order ~~allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised~~from the Court ~~that~~directing the USACE as to how it ~~expects to complete this~~should conduct its additional ~~work by~~review on remand. Dakota Access pipeline and the USACE opposed both motions. On April ~~2018. The~~16, 2018, the Court ~~has stayed consideration of any other claims until it fully resolves the remaining issues relating to its remand order.~~denied both motions.

While ~~we believe~~ETP believes that the pending lawsuits are unlikely to ~~block~~halt or suspend operation of the pipeline, we cannot assure this outcome. WeETP 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 (“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 ~~(CMB)~~ 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 or will be seeking reimbursement for these losses.

MTBE Litigation

Sunoco, Inc. and/or Sunoco, Inc. (R&M) (now known as Sunoco (R&M), ~~along with other refiners, manufacturers and sellers of gasoline,~~LLC) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, ~~typically~~state-level governmental ~~authorities,~~entities, assert product liability, ~~claims and additional claims including~~ nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business ~~practices.~~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, ~~2017,~~2018, Sunoco, Inc. is a defendant in six cases, including ~~cases~~one case each initiated by the States of ~~New Jersey,~~Maryland, Vermont ~~Pennsylvania,~~and Rhode Island, one by the Commonwealth of Pennsylvania and two ~~others~~ by the Commonwealth of Puerto ~~Rico with the~~Rico. The more recent Puerto Rico action ~~being~~is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. ~~Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court.~~

~~Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with~~The actions brought by the State of ~~New Jersey. The~~Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., 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 ~~approved~~previously dismissed. In early September 2018, Sunoco, Inc. participated in a defense group effort to resolve the ~~Judicial Consent Order on October 10, 2017.~~case without further litigation. A settlement in principle to resolve the remaining statewide Vermont Case was reached in September 2018.

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

~~Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported~~Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the ~~Regency Merger.~~Regency-ETP 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 ~~Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB,~~ in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors ~~(the “Regency Litigation~~ (“Defendants”).

The Regency Merger ~~litigation~~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. On March 29, 2016, the Delaware Court of Chancery granted ~~defendants’~~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. ~~The Regency Merger Litigation~~ Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. ~~A hearing on these~~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. Trial is currently set for ~~January 9, 2018.~~September 23-27, 2019.

The Regency ~~Merger Litigation~~ 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 ~~Merger Litigation~~ Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency ~~Litigation~~ 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.

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

On January 27, 2014, a trial commenced between ETP 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 against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise ~~approximately~~ $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and

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pre-judgment interest. The trial court also ordered that ETP 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 motion for rehearing to the Court of Appeals was denied. ~~ETP intends to file a~~On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETP’s petition for review ~~with~~remains under consideration by the Texas Supreme Court.

~~Sunoco Logistics~~ETE-ETP Merger Litigation

~~Seven~~On September 17, 2018, William D. Warner (“Plaintiff”), a purported ~~Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately~~ETP unitholder, filed ~~seven~~a putative ~~unitholder~~ class action ~~lawsuits against ETP, ETP GP, ETP LLC, the members~~asserting violations of various provisions of the ~~ETP Board,~~Securities Exchange Act of 1934 and ~~ETE (the “ETP-SXL Defendants”)~~various rules promulgated thereunder in connection with the ~~announcement~~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 that the Form S-4 Registration Statement issued in connection with the ETE-ETP Merger omits and/or misrepresents material information. Defendants believe the allegations have no merit and intend 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 structure in accordance with the Sunoco Logistics Merger. Two of these lawsuits have been voluntarily dismissed. The five remaining lawsuits have been consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC,Private Securities Litigation Reform Act.

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 ~~Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder~~Louisiana. Plaintiffs allege ~~causes~~that the USACE’s issuance of ~~action challenging~~permits authorizing the ~~merger~~construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the ~~proxy statement/prospectus filed in connection with~~Rivers and Harbors Act. They asked the ~~Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs seek rescission~~district court to vacate these permits and to enjoin construction of the ~~Sunoco Logistics Merger or rescissory damages~~project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETP, 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 ~~ETP unitholders,~~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 ~~well 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.

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 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. Construction is ongoing.

On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an ~~award~~“as applied” challenge to the USACE’s application of ~~costs and attorneys’ fees.~~the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 11, 2018. On September 11, 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.

At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiff’s original complaint, which it has done. Summary judgment briefing will be concluded by the Spring of 2019.

The ETP-SXL Defendants cannot predict the outcome of the Sunoco Logistics Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing, nor can the ETP-SXL Defendants predict the amount of time and expense that will be required to resolve the Sunoco Logistics Merger Litigation. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Sunoco Logistics Merger.

~~Litigation filed by BP Products~~

~~On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC,~~ ~~BP Products North America Inc. v. Sunoco Pipeline L.P.,~~ ~~FERC Docket No. OR15-25~~-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.Rover

On ~~May 26,~~November 3, 2017, the ~~Administrative Law Judge Patricia E. Hurt~~State of Ohio and the Ohio Environmental Protection Agency (“~~ALJ”~~Ohio EPA”) ~~issued her initial decision~~filed suit against Rover and Pretec Directional Drilling, LLC (“~~Initial Decision”~~Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and ~~found that SPLP had acted discriminatorily by entering into T&D agreements~~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 ~~the two shippers other than BP~~Rover and ~~recommended~~Pretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018.

Ohio EPA alleges that the ~~FERC (1) adopt~~Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition.

In January 2018, Ohio EPA sent a letter to the FERC ~~Trial Staff’s $13 million alternative damages proposal, (2) void~~to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the ~~T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history~~Rover Pipeline construction. Rover sent a January 24 response to the ~~level prior to the effective date of the proration policy,~~FERC and ~~(4) investigate the proration policy. The ALJ held~~stated, among other things, that ~~BP’s claim for damages~~as Ohio EPA conceded, Rover was ~~not time-barred~~conducting its drilling operations in ~~its entirety, but~~accordance with specified procedures that ~~it was not entitled to damages more than two years prior to the filing of the complaint.~~

~~On July 26, 2017, each of the parties filed with~~had been approved by the 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 brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.fact with which Ohio EPA concurs.

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, ~~2017~~2018 and December 31, ~~2016,~~2017, accruals of approximately ~~$66~~$55 million and ~~$77~~$53 million, respectively, were reflected on our consolidated balance sheets related to these

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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.

~~In December 2016,~~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 ~~Logistics received multiple Notice of Violations~~Pipeline L.P. (“~~NOVs”~~SPLP”) ~~from~~before the ~~Delaware County Regional Water Quality Control Authority~~Pennsylvania Public Utility Commission (“~~DELCORA”~~PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in ~~connection~~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 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 ~~discharge at its Marcus Hook Industrial Complex~~hearing on May 7, 2018 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“~~MHIC”~~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 ~~2016. Sunoco Logistics~~2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also ~~entered in a Consent Order and Agreement from~~required to provide an affidavit that the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC. These actions propose penalties in excess of $0.1 million, and ETP is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.

~~The Ohio Environmental Protection Agency (“Ohio EPA”)~~ has ~~alleged that various environmental violations have occurred during~~issued appropriate approvals for construction of ME2 and ME2x in the ~~Rover pipeline project. The alleged violations include inadvertent returns~~Township before recommencing construction of ~~drilling muds~~ME2 and ~~fluids at horizontal directional drilling (“HDD”)~~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 ~~Ohio that affected waters~~the Township with respect to four of the ~~State, storm water control violations, improper disposal~~eight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of ~~spent drilling mud containing diesel fuel residuals,~~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. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and ~~open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of approximately $2.3 million in connection with~~intervenors opposed that petition. On September 27, 2018, the alleged violations and is seeking certain corrective actions. ETP is working with Ohio EPA to resolve the matter. The timing or outcome of this matter cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

~~In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC~~Commonwealth Court issued an ~~independent third party assessment~~Order that certified for appeal the issue of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestionsSenator Dinniman’s standing. The Order stays all proceedings in the assessment and to implement additional voluntary protocols. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.

On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.PUC.

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 ~~Pennsylvania Department of Environmental Protection (“PADEP”).~~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 ~~is working to fulfill~~has fulfilled the requirements of those agreements and has been authorized by PADEP to resume drilling ~~at one of~~ the ~~three~~ locations.

No amounts have been recorded in our September 30, ~~2017~~2018 or December 31, ~~2016~~2017 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

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Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on 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 and Louisiana Department of Environmental Quality notifying ~~Sunoco Pipeline L.P. (“SPLP”)~~SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three 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 in February of 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 in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July 2017, we had a ~~follow-up~~ meeting with the DOJ, EPA and Louisiana Department of Environmental Quality (“LDEQ”) during which the agencies presented their initial demand for civil penalties and injunctive relief. ~~In short,~~Since then, the parties have reached an agreement in principal to resolve all penalties with DOJ and ~~EPA proposed federal penalties totaling $7 million for the three releases~~LDEQ along with ~~a demand for~~ injunctive relief requirements to be completed within three years all of which is being formalized in a Consent Decree. In addition to resolution of the civil penalty, we continue to discuss national 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 ~~Louisiana Department~~2X pipelines be stopped. The Administrative Order detailed alleged violations of ~~Environmental Quality proposed a state penalty~~the permits issued by PADEP in February 2017, during the construction of ~~approximately $1 million~~the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the ~~Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined~~compliance issues. Those compliance issues could not be fully resolved by the ~~penalty discussions at this point. We are currently working~~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 ~~counteroffer~~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 ~~Louisiana Department~~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 ~~Quality.~~Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018.

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Environmental Remediation

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

~~Certain~~certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of ~~PCBs.~~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~~certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

~~Currently operating Sunoco, Inc. retail sites previously contributed to Sunoco LP in January 2016.~~

~~Legacy~~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, ~~2017,~~2018, Sunoco, Inc. had been named as a PRP at approximately 4441 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.

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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, 2017		December 31, 2016		September 30, 2018		December 31, 2017
Current	$	36	$	26	$	36	$	36
Non-current	276		283		281		314
Total environmental liabilities	$	312	$	309	$	317	$	350

In 2013, we 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 and 2017, ~~and 2016, Sunoco, Inc.~~the Partnership recorded $4$17 million and ~~$10~~$5 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2018 and 2017, ~~and 2016, Sunoco, Inc.~~the Partnership recorded ~~$14~~$28 million and ~~$24~~$18 million, respectively, of expenditures related to environmental ~~cleanup~~ programs.

~~On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement~~Our pipeline operations are subject to ~~sell~~regulation by the ~~Toledo Refinery~~United States Department of Transportation under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to ~~Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with~~which the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPAPHMSA has ~~not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate~~established requirements relating to the ~~time period that Sunoco, Inc. operated~~design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the ~~refinery. Specifically, EPA~~PHMSA, through the Office of Pipeline Safety, has ~~claimed that~~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 ~~refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/~~rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or ~~in conformance with their design,~~other effective means to assess the integrity of these regulated pipeline segments, and ~~that Sunoco, Inc. submitted semi-annual compliance reports in 2010~~the regulations require prompt action to address integrity issues raised by the assessment and ~~2011 to the EPA that failed to include~~analysis. Integrity testing and assessment of all of these assets will continue, and the ~~information required by~~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 ~~regulations. EPA has proposed penalties in excess~~continued safe and reliable operation of ~~$200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot~~our pipelines; however, no estimate can be ~~reasonably determined~~made at this time ~~however, we do not expect there to be a material impact to our results~~ of ~~operations, cash flows or financial position.~~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, ~~OSHA’s~~the Occupational Health and Safety Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.


11.	REVENUE

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

The Partnership’s consolidated financial statements reflect the following six 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.

Note 14 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.

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 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. As of September 30, 2018, the Partnership had $349 million in deferred revenues representing the current value of our future performance obligations.

The amount of revenue recognized for the three and nine months ended September 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $12 million and $75 million, respectively.

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



	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.	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

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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 on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We ~~use derivatives~~utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in ~~our NGL and~~the price of refined products ~~transportation~~ and ~~services segment~~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 utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. 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, 2017			December 31, 2016			September 30, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Natural Gas (BBtu):
Fixed Swaps/Futures	1,297,500		2017-2018	(682,500	)	2017	358		2018-2019	1,078		2018
Basis Swaps IFERC/NYMEX⁽¹⁾	(15,810,000	)	2017-2019	2,242,500		2017	69,685		2018-2020	48,510		2018-2020
Options – Puts	13,000,000		2018	—		—	(17,273	)	2019	13,000		2018
Power (Megawatt):
Forwards	665,040		2017-2018	391,880		2017-2018	429,720		2018-2019	435,960		2018-2019
Futures	(213,840	)	2017-2018	109,564		2017-2018	309,123		2018-2019	(25,760	)	2018
Options – Puts	(280,800	)	2017-2018	(50,400	)	2017	157,435		2018-2019	(153,600	)	2018
Options – Calls	545,600		2017-2018	186,400		2017	321,240		2018-2019	137,600		2018
Crude (Bbls) – Futures	(160,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	67,500		2017-2020	10,750,000		2017-2018	(7,705	)	2018-2021	4,650		2018-2020
Swing Swaps IFERC	91,897,500		2017-2019	(5,662,500	)	2017	69,145		2018-2019	87,253		2018-2019
Fixed Swaps/Futures	(20,220,000	)	2017-2019	(52,652,500	)	2017-2019	(1,784	)	2018-2020	(4,700	)	2018-2019
Forward Physical Contracts	(140,937,993	)	2017-2018	(22,492,489	)	2017	(54,151	)	2018-2020	(145,105	)	2018-2020
Natural Gas Liquid (Bbls) – Forwards/Swaps	(8,747,200	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(701,000	)	2017	(2,240,000	)	2017
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 (MMBtu):
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2017	(36,370,000	)	2017	(21,475	)	2018-2019	(39,770	)	2018
Fixed Swaps/Futures	(41,102,500	)	2017	(36,370,000	)	2017	(21,475	)	2018-2019	(39,770	)	2018
Hedged Item – Inventory	41,102,500		2017	36,370,000		2017	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				Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2017		December 31, 2016		Type⁽¹⁾	September 30, 2018		December 31, 2017
July 2017⁽²⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200		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 3.64% and receive a floating rate	300		200		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		—		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		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		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, 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 independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

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

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Derivative Summary

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


	Fair Value of Derivative Instruments										Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives						Asset Derivatives				Liability Derivatives
	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016			September 30, 2018		December 31, 2017		September 30, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	7	$	—	$	—		$	(4	)	$	—	$	14	$	(6	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	222		338		(262		)	(416		)	477		262		(537		)	(281		)
Commodity derivatives	50		24		(60		)	(52		)	122		44		(327		)	(55		)
Interest rate derivatives	—		—		(210		)	(193		)	—		—		(97		)	(219		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	272		362		(532		)	(662		)	599		306		(961		)	(555		)
Total derivatives	$	279	$	362	$	(532	)	$	(666	)	$	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								Asset Derivatives						Liability Derivatives
		Balance Sheet Location	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016				Balance Sheet Location	September 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
Derivatives without offsetting agreements		Derivative assets (liabilities)	$	—		$	—		$	(210	)	$	(194	)		Derivative liabilities	$	—		$	—		$	(97	)	$	(219	)
Derivatives in offsetting agreements:	Derivatives in offsetting agreements:														Derivatives in offsetting agreements:
OTC contracts		Derivative assets (liabilities)	50			24			(60		)	(52		)		Derivative assets (liabilities)	122			44			(327		)	(55		)
Broker cleared derivative contracts		Other current assets	229			338			(262		)	(420		)		Other current assets (liabilities)	477			276			(543		)	(283		)
Total gross derivatives	Total gross derivatives		279			362			(532		)	(666		)	Total gross derivatives		599			320			(967		)	(557		)
Offsetting agreements:	Offsetting agreements:														Offsetting agreements:
Counterparty netting		Derivative assets (liabilities)	(10		)	(4		)	10			4				Derivative assets (liabilities)	(29		)	(20		)	29			20
Payments on margin deposit		Other current assets	(220		)	(338		)	220			338
Counterparty netting																Other current assets (liabilities)	(477		)	(263		)	477			263
Total net derivatives	Total net derivatives		$	49		$	20		$	(302	)	$	(324	)	Total net derivatives		$	93		$	37		$	(461	)	$	(274	)

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

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The following tables summarize the amounts recognized in income with respect to our derivative financial instruments:


	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness									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,					Three Months Ended September 30,				Nine Months Ended September 30,
		2017		2016			2017		2016			2018		2017		2018		2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	2	$	(9	)	$	4	$	8	Cost of products sold	$	—	$	2	$	9	$	4
Total		$	2	$	(9	)	$	4	$	8


	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives												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,							Three Months Ended September 30,					Nine Months Ended September 30,
		2017			2016			2017			2016				2018		2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(5	)	$	(8	)	$	21		$	(24	)	Cost of products sold	$	3	$	(5	)	$	36		$	21
Commodity derivatives – Non-trading	Cost of products sold	(12		)	(14		)	(15		)	(57		)	Cost of products sold	21		(12		)	(352		)	(15		)
Interest rate derivatives	Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)	Gains (losses) on interest rate derivatives	45		(8		)	117			(28		)
Embedded derivatives	Other, net	—			8			1			4			Other, net	—		—			—			1
Total		$	(25	)	$	(42	)	$	(21	)	$	(256	)		$	69	$	(25	)	$	(199	)	$	(21	)


13.	RELATED PARTY TRANSACTIONS

~~In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 9.~~

We previously had agreements with ETE to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. These agreements expired in 2016.

The Partnership ~~also~~ has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.

The following table summarizes the affiliate revenues on our consolidated statements of operations:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Affiliated revenues $ 190
$ 63
$ 441
$ 270



	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 related company balances on our consolidated balance sheets:


	September 30, 2017		December 31, 2016		September 30, 2018		December 31, 2017
Accounts receivable from related companies:
ETE	$	—	$	22	$	42	$	—
FGT					15		11
Phillips 66					30		20
Sunoco LP	204		96		207		219
FGT	15		15
Trans-Pecos Pipeline, LLC					10		1
Other	116		76		29		67
Total accounts receivable from related companies:	$	335	$	209	$	333	$	318

Accounts payable to related companies:
Sunoco LP	$	178	$	20	$	178	$	195
USAC					45		—
Other	26		23		64		14
Total accounts payable to related companies:	$	204	$	43	$	287	$	209

September 30, 2017 December 31, 2016
Long-term notes receivable (payable) – related companies:
Sunoco LP $ 85
$ 87
Phillips 66 —
(250 )
Net long-term notes receivable (payable) – related companies $ 85
$ (163 )



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


14.	REPORTABLE SEGMENTS

~~Subsequent to the Sunoco Logistics Merger, our~~Our consolidated financial statements reflect the following reportable segments, which conduct their business in the United States, as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

The amounts included in the NGL and refined products transportation and services segment and the crude oil transportation and services segment have been retrospectively adjusted in these consolidated financial statements as a result of the Sunoco Logistics Merger.

The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from Energy Transfer Partners, L.P. to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from Energy Transfer Partners, L.P. to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP owned by the Partnership. As of September 30, 2017, the Partnership owned 43.5 million Sunoco LP common units, representing 43.7% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.

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

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oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in other.

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unrealized gains and losses on commodity derivatives and inventory fair value ~~adjustments (excluding lower of cost or market adjustments).~~adjustments. Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the ~~Partnership’s~~Partnership's proportionate ownership.

The following tables present financial information by segment:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	729		$	583		$	2,196		$	1,457		$	846		$	729		$	2,424		$	2,196
Intersegment revenues	44			175			146			400			76			44			186			146
	773			758			2,342			1,857			922			773			2,610			2,342
Interstate transportation and storage:
Revenues from external customers	220			231			652			714			390			220			1,026			652
Intersegment revenues	4			5			14			15			5			4			13			14
	224			236			666			729			395			224			1,039			666
Midstream:
Revenues from external customers	665			582			1,863			1,799			537			665			1,571			1,863
Intersegment revenues	1,100			761			3,154			1,966			1,716			1,100			4,170			3,154
	1,765			1,343			5,017			3,765			2,253			1,765			5,741			5,017
NGL and refined products transportation and services:
Revenues from external customers	1,989			1,397			5,874			4,014			2,948			1,989			7,878			5,874
Intersegment revenues	81			148			241			315			115			81			299			241
	2,070			1,545			6,115			4,329			3,063			2,070			8,177			6,115
Crude oil transportation and services:
Revenues from external customers	2,714			1,856			7,749			5,146			4,422			2,714			12,942			7,749
Intersegment revenues	11			—			16			—			16			11			44			16
	2,725			1,856			7,765			5,146			4,438			2,725			12,986			7,765
All other:
Revenues from external customers	656			882			2,110			2,171			498			656			1,490			2,110
Intersegment revenues	27			74			139			350			27			27			108			139
	683			956			2,249			2,521			525			683			1,598			2,249
Eliminations	(1,267		)	(1,163		)	(3,710		)	(3,046		)	(1,955		)	(1,267		)	(4,820		)	(3,710		)
Total revenues	$	6,973		$	5,531		$	20,444		$	15,301		$	9,641		$	6,973		$	27,331		$	20,444

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	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	163		$	133		$	480		$	461		$	221		$	163		$	621		$	480
Interstate transportation and storage	273			278			800			848			416			273			1,069			800
Midstream	356			314			1,088			875			434			356			1,225			1,088
NGL and refined products transportation and services	423			383			1,196			1,072			498			439			1,410			1,208
Crude oil transportation and services	396			169			830			521			682			420			1,694			835
All other	133			113			363			395			78			133			242			363
Total	1,744			1,390			4,757			4,172			2,329			1,784			6,261			4,774
Depreciation, depletion and amortization	(596		)	(503		)	(1,713		)	(1,469		)	(636		)	(596		)	(1,827		)	(1,713		)
Interest expense, net	(367		)	(345		)	(1,052		)	(981		)	(387		)	(352		)	(1,091		)	(1,020		)
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Non-cash unit-based compensation expense	(19		)	(22		)	(57		)	(60		)
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	(81		)	(15		)	17			(96		)	97			(81		)	(255		)	17
Inventory valuation adjustments	86			37			30			143
Adjusted EBITDA related to unconsolidated affiliates	(279		)	(240		)	(765		)	(711		)	(257		)	(279		)	(670		)	(765		)
Equity in earnings of unconsolidated affiliates	127			65			139			260			113			127			147			139
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Other, net	42			43			111			84			13			27			100			79
Income before income tax expense (benefit)	$	649		$	74		$	1,439		$	855
Income before income tax (expense) benefit													$	1,297		$	603		$	2,807		$	1,426

* As adjusted. See Note 1.


	September 30, 2017		December 31, 2016		September 30, 2018		December 31, 2017
Assets:
Intrastate transportation and storage	$	5,179	$	5,164	$	5,874	$	5,020
Interstate transportation and storage	12,194		10,833		14,143		13,518
Midstream	19,781		17,873		20,175		20,004
NGL and refined products transportation and services	16,445		14,128		18,438		17,600
Crude oil transportation and services	17,267		15,941		17,458		17,736
All other	6,145		6,252		3,068		4,087
Total assets	$	77,011	$	70,191	$	79,156	$	77,965


15.	CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

~~Prior to the Sunoco Logistics Merger,~~ Sunoco Logistics Partners Operations L.P., a subsidiary of ~~Sunoco Logistics was~~ETP, is the issuer of multiple series of senior notes that ~~were~~are guaranteed by ~~Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company.~~

ETP. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer ~~Partners,~~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.

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To present the supplemental condensed consolidating financial information on a comparable basis, the prior period financial information has been recast as if the Sunoco Logistics Merger occurred on January 1, 2016.

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


	September 30, 2017													September 30, 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	$	—		$	49		$	330	$	—		$	379	$	—		$	—		$	379	$	—		$	379
All other current assets	—			77			5,324		—			5,401		4			56			6,806		(892		)	5,974
Property, plant and equipment, net	—			—			56,972		—			56,972		—			—			60,550		—			60,550
Investments in unconsolidated affiliates	25,174			11,605			4,221		(36,779		)	4,221		49,614			12,435			3,599		(62,049		)	3,599
All other assets	—			25			10,013		—			10,038		8			75			8,571		—			8,654
Total assets	$	25,174		$	11,756		$	76,860	$	(36,779	)	$	77,011	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156

Current liabilities	$	(1,494	)	$	(3,819	)	$	12,199	$	—		$	6,886	$	(1,118	)	$	(3,407	)	$	14,675	$	(892	)	$	9,258
Non-current liabilities	—			7,664			31,604		—			39,268		22,823			7,605			4,794		—			35,222
Noncontrolling interest	—			—			4,191		—			4,191		—			—			6,334		—			6,334
Total partners’ capital	26,668			7,911			28,866		(36,779		)	26,666		27,921			8,368			54,102		(62,049		)	28,342
Total liabilities and equity	$	25,174		$	11,756		$	76,860	$	(36,779	)	$	77,011	$	49,626		$	12,566		$	79,905	$	(62,941	)	$	79,156


	December 31, 2016													December 31, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership		Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	41		$	319	$	—		$	360	$	—		$	(3	)	$	309	$	—		$	306
All other current assets	—			2			5,367		—			5,369		—			159			6,063		—			6,222
Property, plant and equipment, net	—			—			50,917		—			50,917		—			—			58,437		—			58,437
Investments in unconsolidated affiliates	23,350			10,664			4,280		(34,014		)	4,280		48,378			11,648			3,816		(60,026		)	3,816
All other assets	—			5			9,260		—			9,265		—			—			9,184		—			9,184
Total assets	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

Current liabilities	$	(1,761	)	$	(3,800	)	$	11,764	$	—		$	6,203	$	(1,496	)	$	(3,660	)	$	12,150	$	—		$	6,994
Non-current liabilities	299			7,313			30,148		(299		)	37,461		21,604			7,607			7,609		—			36,820
Noncontrolling interest	—			—			1,297		—			1,297		—			—			5,882		—			5,882
Total partners’ capital	24,812			7,199			26,934		(33,715		)	25,230		28,270			7,857			52,168		(60,026		)	28,269
Total liabilities and equity	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

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	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		$	—		$	—		$	9,641		$	—		$	9,641
Operating costs, expenses, and other	—		—			6,148			—			6,148			—			—			8,136			—			8,136
Operating income	—		—			825			—			825			—			—			1,505			—			1,505
Interest expense, net	—		(32		)	(335		)	—			(367		)	(303		)	(55		)	(29		)	—			(387		)
Equity in earnings of unconsolidated affiliates	647		236			127			(883		)	127			1,394			501			113			(1,895		)	113
Losses on interest rate derivatives	—		—			(8		)	—			(8		)
Gains on interest rate derivatives															45			—			—			—			45
Other, net	—		1			71			—			72			—			—			21			—			21
Income before income tax benefit	647		205			680			(883		)	649			1,136			446			1,610			(1,895		)	1,297
Income tax benefit	—		—			(112		)	—			(112		)	—			—			(61		)	—			(61		)
Net income	647		205			792			(883		)	761			1,136			446			1,671			(1,895		)	1,358
Less: Net income attributable to noncontrolling interest	—		—			110			—			110			—			—			223			—			223
Net income attributable to partners	$	647	$	205		$	682		$	(883	)	$	651		$	1,136		$	446		$	1,448		$	(1,895	)	$	1,135

Other comprehensive income	$	—	$	—		$	7		$	—		$	7		$	—		$	—		$	4		$	—		$	4
Comprehensive income	647		205			799			(883		)	768			1,136			446			1,675			(1,895		)	1,362
Comprehensive income attributable to noncontrolling interest	—		—			110			—			110			—			—			223			—			223
Comprehensive income attributable to partners	$	647	$	205		$	689		$	(883	)	$	658		$	1,136		$	446		$	1,452		$	(1,895	)	$	1,139


	Three Months Ended September 30, 2016														Three Months Ended September 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership			Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	5,531		$	—		$	5,531		$	—	$	—		$	6,973		$	—		$	6,973
Operating costs, expenses, and other	—		—			4,893			—			4,893			—		—			6,194			—			6,194
Operating income	—		—			638			—			638			—		—			779			—			779
Interest expense, net	—		(39		)	(306		)	—			(345		)	—		(32		)	(320		)	—			(352		)
Equity in earnings of unconsolidated affiliates	119		193			65			(312		)	65			647		236			127			(883		)	127
Impairment of investment in an unconsolidated affiliate	—		—			(308		)	—			(308		)
Losses on interest rate derivatives	—		—			(28		)	—			(28		)	—		—			(8		)	—			(8		)
Other, net	—		—			52			—			52			—		1			56			—			57
Income before income tax benefit	119		154			113			(312		)	74			647		205			634			(883		)	603
Income tax benefit	—		—			(64		)	—			(64		)	—		—			(112		)	—			(112		)
Net income	119		154			177			(312		)	138			647		205			746			(883		)	715
Less: Net income attributable to noncontrolling interest	—		—			21			—			21			—		—			110			—			110
Net income attributable to partners	$	119	$	154		$	156		$	(312	)	$	117		$	647	$	205		$	636		$	(883	)	$	605

Other comprehensive income	$	—	$	—		$	2		$	—		$	2		$	—	$	—		$	7		$	—		$	7
Comprehensive income	119		154			179			(312		)	140			647		205			753			(883		)	722
Comprehensive income attributable to noncontrolling interest	—		—			21			—			21			—		—			110			—			110
Comprehensive income attributable to partners	$	119	$	154		$	158		$	(312	)	$	119		$	647	$	205		$	643		$	(883	)	$	612

* As adjusted. See Note 1.

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	Nine Months Ended September 30, 2017														Nine 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	$	—	$	—		$	20,444		$	—		$	20,444		$	—		$	—		$	27,331		$	—		$	27,331
Operating costs, expenses, and other	—		1			18,232			—			18,233			—			—			23,910			—			23,910
Operating income (loss)	—		(1		)	2,212			—			2,211
Operating income															—			—			3,421			—			3,421
Interest expense, net	—		(113		)	(939		)	—			(1,052		)	(870		)	(137		)	(84		)	—			(1,091		)
Equity in earnings of unconsolidated affiliates	1,657		1,001			139			(2,658		)	139			3,036			827			147			(3,863		)	147
Losses on interest rate derivatives	—		—			(28		)	—			(28		)
Gain on Sunoco LP unit repurchase															—			—			172			—			172
Loss on deconsolidation of CDM															—			—			(86		)	—			(86		)
Gains on interest rate derivatives															117			—			—			—			117
Other, net	—		4			166			(1		)	169			—			—			127			—			127
Income before income tax expense	1,657		891			1,550			(2,659		)	1,439
Income tax expense	—		—			22			—			22
Income before income tax benefit															2,283			690			3,697			(3,863		)	2,807
Income tax benefit															—			—			(32		)	—			(32		)
Net income	1,657		891			1,528			(2,659		)	1,417			2,283			690			3,729			(3,863		)	2,839
Less: Net income attributable to noncontrolling interest	—		—			216			—			216			—			—			557			—			557
Net income attributable to partners	$	1,657	$	891		$	1,312		$	(2,659	)	$	1,201		$	2,283		$	690		$	3,172		$	(3,863	)	$	2,282

Other comprehensive income	$	—	$	—		$	6		$	—		$	6		$	—		$	—		$	7		$	—		$	7
Comprehensive income	1,657		891			1,534			(2,659		)	1,423			2,283			690			3,736			(3,863		)	2,846
Comprehensive income attributable to noncontrolling interest	—		—			216			—			216			—			—			557			—			557
Comprehensive income attributable to partners	$	1,657	$	891		$	1,318		$	(2,659	)	$	1,207		$	2,283		$	690		$	3,179		$	(3,863	)	$	2,289


	Nine Months Ended September 30, 2016														Nine Months Ended September 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership			Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	15,301		$	—		$	15,301		$	—	$	—		$	20,444		$	—		$	20,444
Operating costs, expenses, and other	—		1			13,333			—			13,334			—		1			18,245			—			18,246
Operating income (loss)	—		(1		)	1,968			—			1,967			—		(1		)	2,199			—			2,198
Interest expense, net	—		(116		)	(865		)	—			(981		)	—		(113		)	(907		)	—			(1,020		)
Equity in earnings of unconsolidated affiliates	930		618			260			(1,548		)	260			1,657		1,001			139			(2,658		)	139
Impairment of investment in an unconsolidated affiliate	—		—			(308		)	—			(308		)
Losses on interest rate derivatives	—		—			(179		)	—			(179		)	—		—			(28		)	—			(28		)
Other, net	—		—			96			—			96			—		4			134			(1		)	137
Income before income tax benefit	930		501			972			(1,548		)	855
Income tax benefit	—		—			(131		)	—			(131		)
Income before income tax expense															1,657		891			1,537			(2,659		)	1,426
Income tax expense															—		—			22			—			22
Net income	930		501			1,103			(1,548		)	986			1,657		891			1,515			(2,659		)	1,404
Less: Net income attributable to noncontrolling interest	—		—			57			—			57			—		—			266			—			266
Net income attributable to partners	$	930	$	501		$	1,046		$	(1,548	)	$	929		$	1,657	$	891		$	1,249		$	(2,659	)	$	1,138

Other comprehensive loss	$	—	$	—		$	(8	)	$	—		$	(8	)
Other comprehensive income															$	—	$	—		$	6		$	—		$	6
Comprehensive income	930		501			1,095			(1,548		)	978			1,657		891			1,521			(2,659		)	1,410
Comprehensive income attributable to noncontrolling interest	—		—			57			—			57			—		—			266			—			266
Comprehensive income attributable to partners	$	930	$	501		$	1,038		$	(1,548	)	$	921		$	1,657	$	891		$	1,255		$	(2,659	)	$	1,144

* As adjusted. See Note 1.

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	Nine Months Ended September 30, 2017															Nine 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
Cash flows provided by operating activities	$	1,657		$	802		$	3,538		$	(2,660	)	$	3,337		$	2,753		$	582		$	3,843		$	(2,078	)	$	5,100
Cash flows used in investing activities	(1,348		)	(1,127		)	(4,872		)	2,660			(4,687		)	(834		)	(579		)	(3,732		)	2,078			(3,067		)
Cash flows provided by (used in) financing activities	(309		)	333			1,345			—			1,369
Cash flows used in financing activities																(1,919		)	—			(41		)	—			(1,960		)
Change in cash	—			8			11			—			19			—			3			70			—			73
Cash at beginning of period	—			41			319			—			360			—			(3		)	309			—			306
Cash at end of period	$	—		$	49		$	330		$	—		$	379		$	—		$	—		$	379		$	—		$	379


	Nine Months Ended September 30, 2016															Nine Months Ended September 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership			Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	929		$	491		$	2,593		$	(1,548	)	$	2,465		$	1,657		$	802		$	3,538		$	(2,660	)	$	3,337
Cash flows used in investing activities	(1,537		)	(918		)	(2,733		)	1,548			(3,640		)	(1,348		)	(1,127		)	(4,872		)	2,660			(4,687		)
Cash flows provided by (used in) financing activities	606			429			(10		)	—			1,025			(309		)	333			1,345			—			1,369
Change in cash	(2		)	2			(150		)	—			(150		)	—			8			11			—			19
Cash at beginning of period	—			37			490			—			527			—			41			319			—			360
Cash at end of period	$	(2	)	$	39		$	340		$	—		$	377		$	—		$	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 ~~except per unit data,~~ are in millions)

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in ~~Exhibit 99.1 to~~ the Partnership’s ~~Current~~Annual Report on Form ~~8-K~~10-K filed with the SEC on ~~August 14, 2017.~~February 23, 2018. 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, ~~2016~~2017 filed with the SEC on February ~~24, 2017 and Exhibit 99.3 to the Partnership’s Current Report on Form 8-K filed with the SEC on May 8, 2017.~~23, 2018.

References to “we,” “us,” “our,” the “Partnership” and “ETP” shall mean Energy Transfer Operating, L.P. (formerly Energy Transfer Partners, L.P.) and its subsidiaries. ~~See Note 1 to the consolidated financial statements for information related to the entity’s recent name change.~~

OVERVIEW

The primary activities and operating subsidiaries through which we conduct those activities are as follows:

Natural gas operations, 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

In 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. The 600-mile PGC pipeline system is expected to be operational 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 is subject to receipt of customary regulatory and Board approvals of the respective entities.

ETE 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 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.

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.

ETP Senior Notes Offering and Redemption

In ~~October 2017, the Partnership redeemed all of the outstanding~~June 2018, ETP issued $500 million aggregate principal amount of ~~ETLP’s 6.50%~~4.20% senior notes due ~~July 2021 and all~~2023, $1.00 billion aggregate principal amount of ~~the outstanding $700~~4.95% senior notes due 2028, $500 million aggregate principal amount of ~~ETLP’s 5.50%~~5.80% senior notes due ~~April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.~~

~~ETP Senior Notes Offering~~

~~In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027~~2038 and ~~$1.50~~$1.00 billion aggregate principal amount of ~~5.40%~~6.00% senior notes due ~~2047.~~2048. The ~~$2.22~~$2.96 billion net proceeds from the offering were used to redeem ~~all of the $500 million aggregate principal amount of ETLP’s 6.5%~~outstanding senior notes, ~~due 2021,~~ to repay borrowings outstanding under ~~the Sunoco Logistics Credit Facility~~ETP’s revolving credit facility and for general partnership purposes.

~~August 2017 Units Offering~~Old Ocean Joint Venture Formation

In ~~August 2017,~~May 2018, ETP and Enterprise Products Partners L.P. announced the ~~Partnership~~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.

Acquisition of HPC

Series C Preferred Units Issuance

In April 2018, ETP issued 5418 million ~~ETP common units~~of its 7.375% Series C Preferred Units at a price of $25 per unit, resulting in ~~an underwritten public offering. Net~~total gross proceeds of ~~$997 million from the offering~~$450 million. The proceeds were used ~~by the Partnership~~ to repay amounts outstanding under ~~its~~ETP’s revolving credit ~~facilities, to fund capital expenditures~~facility and for general partnership purposes.

~~Rover~~CDM Contribution ~~Agreement~~

~~In July 2017,~~On April 2, 2018, ETP ~~announced~~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 ~~it had entered into~~have substantially all of the rights and obligations of a ~~contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”),~~USAC common unit, except the USAC Class B Units will not participate in distributions for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP throughfirst four quarters following the closing date ~~along~~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.

In connection with the ~~payment~~CDM Contribution, ETE acquired (i) all of ~~additional amounts subject~~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 ~~certain adjustments. The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by~~$250 million.

New Ethane Export Facility Joint Venture

In March 2018, ETP and ~~49.9% by Blackstone.~~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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~~PennTex Tender Offer~~wholly own the infrastructure that is required to both supply ethane to the pipeline and ~~Limited Call Right Exercise~~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

In ~~June~~February 2018, after the record date for Sunoco LP’s fourth quarter 2017 ~~ETP purchased all of the outstanding PennTex~~cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units ~~not previously~~ owned by ETP for ~~$20.00 per common unit in cash.~~aggregate cash consideration of approximately $540 million. ETP ~~now owns all~~used the proceeds from the sale of the ~~economic interests of PennTex, and PennTex~~Sunoco LP common units ~~are~~to repay amounts outstanding under its revolving credit facility.

Regulatory Update

Interstate Natural Gas Transportation Regulation

Effective December 22, 2017, 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 ~~publicly traded or listed~~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. 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 ~~NASDAQ.~~treatment of income taxes may have on the rates ETP can charge for the FERC regulated transportation services are unknown at this time.

~~Sunoco Logistics Merger~~The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) 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.

~~In April 2017, Energy Transfer Partners, L.P.~~Included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and ~~Sunoco Logistics completed~~ the ~~merger transaction (the “Sunoco Logistics Merger”~~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: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates only as required related to the Tax Act and the Revised Policy Statement, commit to filing a general NGA Section 4 rate case in ~~which Sunoco Logistics acquired Energy Transfer Partners, L.P.~~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 their respective FERC Form No. 501-Gs by November 8, 2018. Rover, FGT, Transwestern and MEP are scheduled to file their respective FERC Form No. 501-Gs by December 6, 2018. At this time, we cannot predict the outcome of the Final Rule, but adoption of the regulation could ultimately result in a ~~unit-for-unit transaction. Under~~rate proceeding that may impact the ~~terms~~rates ETP is permitted to charge its customers for FERC regulated transportation services.

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 ~~transaction,~~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 ~~unitholders received 1.5 common units~~cost of ~~Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under~~service rates to be affected by the ~~terms~~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 ~~merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.~~

~~Permian Express Partners~~

In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the dateultimate outcome of the ~~contribution, including $547 million of intangible assets~~NOI, the Final Rule, and ~~$435 million of property, plant and equipment.~~

~~In July 2017,~~ the ~~Partnership contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase~~Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the ~~Partnership’s ownership interest in PEP~~Tax Act. The extent of any revenue reduction related to ~~approximately 88%. The Partnership maintains~~our cost of service rates, if any, will depend on a ~~controlling financial and voting interest in PEP and is the operator~~detailed review of all of ETP’s cost of service components and the ~~assets. As such, PEP~~outcomes of any challenges to our rates by the FERC or our shippers.

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 ~~reflected~~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 ~~consolidated subsidiary~~result of the ~~Partnership. ExxonMobil’s interest~~Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in ~~PEP is reflected as noncontrolling interest~~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 ~~consolidated balance sheets. ExxonMobil’s contribution resulted~~United States.

Interstate Liquids Transportation Regulation

The FERC utilizes an indexing rate methodology which, as currently in ~~an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest”~~effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the ~~consolidated statement~~Producer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of ~~equity.~~

~~Bakken Equity Sale~~

~~In February 2017, Bakken Holdings Company LLC, an entity in which~~market-based rates. The FERC’s indexing methodology is subject to review every five years. During the ~~Partnership indirectly owns a 100% membership interest, sold a 49% interest~~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 July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by the FERC in its ~~wholly-owned subsidiary, Bakken Pipeline Investments LLC,~~next five year review of the liquids pipeline index to ~~MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation~~generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and ~~Enbridge Energy Partners, L.P.,~~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 ~~$2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each~~income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of ~~Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July 2017,~~ the ~~Partnership contributed a portion~~appropriate pipeline index. Accordingly, depending on the FERC’s application of its ~~ownership interest~~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 ~~Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.~~the future, including indexed rates.

Results of Operations

We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA 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 (excluding lower of cost or market adjustments).~~adjustments. Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.

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~~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 of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain

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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,
	2017			2016			Change			2017			2016			Change			2018			2017*			Change			2018			2017*			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	163		$	133		$	30		$	480		$	461		$	19		$	221		$	163		$	58		$	621		$	480		$	141
Interstate transportation and storage	273			278			(5		)	800			848			(48		)	416			273			143			1,069			800			269
Midstream	356			314			42			1,088			875			213			434			356			78			1,225			1,088			137
NGL and refined products transportation and services	423			383			40			1,196			1,072			124			498			439			59			1,410			1,208			202
Crude oil transportation and services	396			169			227			830			521			309			682			420			262			1,694			835			859
All other	133			113			20			363			395			(32		)	78			133			(55		)	242			363			(121		)
Total	1,744			1,390			354			4,757			4,172			585			2,329			1,784			545			6,261			4,774			1,487
Depreciation, depletion and amortization	(596		)	(503		)	(93		)	(1,713		)	(1,469		)	(244		)	(636		)	(596		)	(40		)	(1,827		)	(1,713		)	(114		)
Interest expense, net	(367		)	(345		)	(22		)	(1,052		)	(981		)	(71		)	(387		)	(352		)	(35		)	(1,091		)	(1,020		)	(71		)
Losses on interest rate derivatives	(8		)	(28		)	20			(28		)	(179		)	151
Non-cash unit-based compensation expense	(19		)	(22		)	3			(57		)	(60		)	3
Gain on Sunoco LP common unit repurchase																			—			—			—			172			—			172
Loss on deconsolidation of CDM																			—			—			—			(86		)	—			(86		)
Gains (losses) on interest rate derivatives																			45			(8		)	53			117			(28		)	145
Non-cash compensation expense																			(20		)	(19		)	(1		)	(61		)	(57		)	(4		)
Unrealized gains (losses) on commodity risk management activities	(81		)	(15		)	(66		)	17			(96		)	113			97			(81		)	178			(255		)	17			(272		)
Inventory valuation adjustments	86			37			49			30			143			(113		)
Adjusted EBITDA related to unconsolidated affiliates	(279		)	(240		)	(39		)	(765		)	(711		)	(54		)	(257		)	(279		)	22			(670		)	(765		)	95
Equity in earnings of unconsolidated affiliates	127			65			62			139			260			(121		)	113			127			(14		)	147			139			8
Impairment of investment in an unconsolidated affiliate	—			(308		)	308			—			(308		)	308
Other, net	42			43			(1		)	111			84			27			13			27			(14		)	100			79			21
Income before income tax expense (benefit)	649			74			575			1,439			855			584
Income tax expense (benefit)	(112		)	(64		)	(48		)	22			(131		)	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
Net income	$	761		$	138		$	623		$	1,417		$	986		$	431		$	1,358		$	715		$	643		$	2,839		$	1,404		$	1,435

* As adjusted.

See the detailed discussion of Segment Adjusted EBITDA and Segment Operating Results.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased for the three and nine months ended September 30, ~~2017~~2018 compared to the same ~~periods~~period last year primarily due to additional depreciation from assets recently placed in ~~service~~service. These increases were partially offset by the deconsolidation of CDM in April 2018, which reduced depreciation and ~~recent acquisitions.~~amortization expense by $43 million and $78 million for the three and nine months ended September 30, 2018, respectively, compared to the prior periods.

Interest Expense, net. Interest expense, net of capitalized interest, increased for the three and nine months ended September 30, ~~2017~~2018 compared to the same ~~periods~~period last year primarily attributable to increases in long-term debt ~~including~~from ETP senior note issuances, partially offset by a decrease in credit facility borrowings.

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Gain on Sunoco LP Common Unit Repurchase. In connection with Sunoco LP’s repurchase of its common units in February 2018, the ~~Dakota Access and ETCO term loans that became effective in August 2016.~~Partnership recognized a gain of $172 million during the nine months ended September 30, 2018.

~~Losses~~Loss on Deconsolidation of CDM. In connection with the CDM Contribution in April 2018, the Partnership deconsolidated CDM and recognized a loss of $86 million during the nine months ended September 30, 2018.

Gains (Losses) on Interest Rate Derivatives. ~~Losses~~Gains on interest rate derivatives during the three and nine months ended September 30, ~~2017 and 2016~~2018 resulted from ~~decreases~~increases in forward interest rates, which caused our forward-starting swaps to change in value.

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

~~Inventory Valuation Adjustments.~~ ~~Inventory valuation reserve adjustments were recorded for crude oil, NGLs and refined products inventories as a result of commodity price changes during the respective periods.~~

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Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.

Other, net. Includes amortization of regulatory assets and other income and expense amounts.

Income Tax ~~Expense (Benefit).~~(Expense) Benefit. For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the period. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. The three and nine months ended September 30, 2017 also reflect increased income tax expense due to higher earnings among the Partnership’s consolidated corporate subsidiaries. For the three and nine months ended September 30, ~~2016,~~2018 compared to the ~~Partnership’s~~same period last year, income tax expense decreased primarily due to the decrease in federal corporate income tax rate per the Tax Act as well as $109 million and $179 million, respectively, of deferred tax benefit ~~primarily resulted from losses among~~adjustments during the ~~Partnership’s consolidated corporate subsidiaries.~~three and nine months ended September 30, 2018 as the result of a state statutory rate reduction.

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Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:


	Three Months Ended September 30,								Nine Months Ended September 30,									Three Months Ended September 30,								Nine Months Ended September 30,
	2017		2016			Change			2017			2016			Change			2018			2017		Change			2018			2017			Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	35	$	31		$	4		$	86		$	80		$	6		$	42		$	35	$	7		$	102		$	86		$	16
FEP	14		12			2			39			38			1			14			14		—			41			39			2
PES	11		(26		)	37			5			(25		)	30
MEP	9		9			—			29			31			(2		)	7			9		(2		)	24			29			(5		)
HPC	5		8			(3		)	17			23			(6		)
Sunoco LP	35		16			19			(89		)	54			(143		)	29			35		(6		)	(106		)	(89		)	(17		)
USAC																		(4		)	—		(4		)	(6		)	—			(6		)
Other	18		15			3			52			59			(7		)	25			34		(9		)	92			74			18
Total equity in earnings of unconsolidated affiliates	$	127	$	65		$	62		$	139		$	260		$	(121	)	$	113		$	127	$	(14	)	$	147		$	139		$	8

Adjusted EBITDA related to unconsolidated affiliates⁽¹⁾:
Citrus	$	99	$	90		$	9		$	262		$	251		$	11		$	96		$	99	$	(3	)	$	256		$	262		$	(6	)
FEP	18		19			(1		)	55			56			(1		)	19			18		1			56			55			1
PES	15		(19		)	34			31			2			29
MEP	23		22			1			66			69			(3		)	20			23		(3		)	62			66			(4		)
HPC	13		15			(2		)	40			45			(5		)
Sunoco LP	74		83			(9		)	211			208			3			58			74		(16		)	126			211			(85		)
USAC																		20			—		20			41			—			41
Other	37		30			7			100			80			20			44			65		(21		)	129			171			(42		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	279	$	240		$	39		$	765		$	711		$	54		$	257		$	279	$	(22	)	$	670		$	765		$	(95	)

Distributions received from unconsolidated affiliates:
Citrus	$	50	$	50		$	—		$	113		$	112		$	1		$	52		$	50	$	2		$	125		$	113		$	12
FEP	18		17			1			28			47			(19		)	18			18		—			50			28			22
MEP	13		17			(4		)	106			56			50			9			13		(4		)	40			106			(66		)
HPC	9		13			(4		)	22			38			(16		)
Sunoco LP	36		36			—			108			102			6			21			36		(15		)	79			108			(29		)
USAC																		10			—		10			20			—			20
Other	18		16			2			58			49			9			34			27		7			76			80			(4		)
Total distributions received from unconsolidated affiliates	$	144	$	149		$	(5	)	$	435		$	404		$	31		$	144		$	144	$	—		$	390		$	435		$	(45	)


⁽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.

~~Table of Contents~~

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

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

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

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.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment ~~Margin~~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~~margin is similar to the GAAP measure of gross margin, except that ~~Segment Margin~~segment margin excludes charges for depreciation, depletion and amortization.

In addition, for certain segments, the sections below include information on the components of ~~Segment Margin~~segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of ~~Segment Margin~~segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of ~~Segment Margin~~segment margin are calculated consistent with the calculation of ~~Segment Margin;~~segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Segment Margin:
Intrastate transportation and storage	$	167		$	172		$	551		$	525		$	284		$	167		$	722		$	551
Interstate transportation and storage	224			236			666			729			395			224			1,039			666
Midstream	530			476			1,614			1,350			622			530			1,768			1,614
NGL and refined products transportation and services	488			484			1,563			1,357			634			483			1,821			1,558
Crude oil transportation and services	588			266			1,202			852			944			548			1,954			1,194
All other	112			79			290			258			25			112			177			290
Intersegment eliminations	(12		)	(26		)	(24		)	(50		)	(8		)	(13		)	(23		)	(24		)
Total Segment Margin	2,097			1,687			5,862			5,021
Total segment margin													2,896			2,051			7,458			5,849

Less:
Operating expenses	571			475			1,603			1,359			632			571			1,863			1,603
Depreciation, depletion and amortization	596			503			1,713			1,469			636			596			1,827			1,713
Selling, general and administrative	105			71			335			226			123			105			347			335
Operating income	$	825		$	638		$	2,211		$	1,967		$	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,
	2017			2016			Change			2017			2016			Change			2018			2017			Change			2018			2017			Change
Natural gas transported (MMBtu/d)	8,942,066			8,289,826			652,240			8,695,047			8,392,641			302,406
Natural gas transported (BBtu/d)																			12,146			8,951			3,195			10,592			8,698			1,894
Withdrawals from storage natural gas inventory (BBtu)																			—			—			—			17,703			23,093			(5,390		)
Revenues	$	773		$	758		$	15		$	2,342		$	1,857		$	485		$	922		$	773		$	149		$	2,610		$	2,342		$	268
Cost of products sold	606			586			20			1,791			1,332			459			638			606			32			1,888			1,791			97
Segment margin	167			172			(5		)	551			525			26			284			167			117			722			551			171
Unrealized (gains) losses on commodity risk management activities	22			(7		)	29			16			24			(8		)	(12		)	22			(34		)	33			16			17
Operating expenses, excluding non-cash compensation expense	(40		)	(43		)	3			(124		)	(117		)	(7		)	(51		)	(40		)	(11		)	(141		)	(124		)	(17		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(6		)	(5		)	(1		)	(17		)	(17		)	—			(7		)	(6		)	(1		)	(20		)	(17		)	(3		)
Adjusted EBITDA related to unconsolidated affiliates	19			15			4			53			45			8			6			19			(13		)	26			53			(27		)
Other	1			1			—			1			1			—			1			1			—			1			1			—
Segment Adjusted EBITDA	$	163		$	133		$	30		$	480		$	461		$	19		$	221		$	163		$	58		$	621		$	480		$	141

Volumes. For the three and nine months ended September 30, ~~2017~~2018 compared to the same ~~periods~~period last year, transported volumes increased primarily due to ~~higher demand for exports to Mexico, along with~~favorable market pricing, as well as the ~~addition~~impact of ~~new pipes to our intrastate pipeline system. These increases were partially offset by lower production volumes~~reflecting RIGS as a consolidated subsidiary beginning in ~~the Barnett Shale region.~~April 2018, as discussed in “Recent Developments” above.

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Transportation fees $ 108
$ 122
$ (14 ) $ 337
$ 381
$ (44 )
Natural gas sales and other 42
26
16
140
81
59
Retained fuel revenues 14
14
—
48
34
14
Storage margin, including fees 3
10
(7 ) 26
29
(3 )
Total segment margin $ 167
$ 172
$ (5 ) $ 551
$ 525
$ 26



	Three Months Ended September 30,								Nine Months Ended September 30,
	2018		2017			Change			2018			2017			Change
Transportation fees	$	141	$	109		$	32		$	392		$	337		$	55
Natural gas sales and other (excluding unrealized gains and losses)	110		55			55			309			149			160
Retained fuel revenues (excluding unrealized gains and losses)	16		15			1			42			43			(1		)
Storage margin (excluding unrealized gains and losses)	5		10			(5		)	12			38			(26		)
Unrealized gains (losses) on commodity risk management activities	12		(22		)	34			(33		)	(16		)	(17		)
Total segment margin	$	284	$	167		$	117		$	722		$	551		$	171

Segment Adjusted EBITDA. For the three months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our~~ETP’s intrastate transportation and storage segment increased due to the net impacts of the following:

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

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 compared to the same period last year, Segment Adjusted EBITDA related to ETP’s intrastate transportation and storage segment increased due to the net impacts of the following:

an increase of $160 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity;

an increase 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

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,
	2018			2017			Change			2018			2017			Change
Natural gas transported (BBtu/d)	10,155			6,075			4,080			9,029			5,678			3,351
Natural gas sold (BBtu/d)	18			19			(1		)	17			18			(1		)
Revenues	$	395		$	224		$	171		$	1,039		$	666		$	373
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(97		)	(79		)	(18		)	(296		)	(220		)	(76		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(19		)	(14		)	(5		)	(53		)	(33		)	(20		)
Adjusted EBITDA related to unconsolidated affiliates	135			140			(5		)	374			383			(9		)
Other	2			2			—			5			4			1
Segment Adjusted EBITDA	$	416		$	273		$	143		$	1,069		$	800		$	269

Volumes. For the three months ended September 30, 2018 compared to the same period last year, transported volumes reflected an increase of 2,225 BBtu/d as a result of the initiation of service on 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 production increases in the Haynesville Shale and deliveries into intrastate markets.

For the nine months ended September 30, 2018 compared to the same period last year, transported volumes reflected increases of 1,817 BBtu/d as a result of the initiation of service on the Rover pipeline; increases of 594 BBtu/d and 428 BBtu/d 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.

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

an increase of ~~$29~~$128 million associated with the Rover pipeline with increases of $149 million in ~~natural gas sales~~revenues, $14 million in net operating expenses and ~~other (excluding net changes~~$7 million in ~~unrealized gains~~selling, general and ~~losses~~administrative expenses; and

Table of ~~$13 million)~~Contents

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 ~~realized gains from pipeline optimization activity;~~

rates on the Transwestern and Panhandle pipelines; partially offset by

an increase of $9 million in storage margin (excluding net changes in unrealized gains and losses of $16 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below;

~~a decrease of $3~~$4 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to ~~the timing~~slightly higher system gas expense and higher maintenance project costs due to scope and level of ~~project related expenses of $3 million, lower allocated expenses and lower capitalized overhead of $2 million, partially~~activity, offset by ~~higher outside services~~lower ad valorem taxes due to favorable valuations; and ~~employee expenses~~

a decrease of ~~$2 million; and~~

~~an increase of $4~~$5 million in Adjusted EBITDA related to unconsolidated affiliates ~~due~~primarily related to ~~two new joint venture pipelines placed in service in 2017; partially offset by~~

~~a decrease in transportation fees~~sale of ~~$14 million due to renegotiated contracts resulting in~~capacity on MEP at lower ~~billed volumes, offset by increased margin from optimization activity recorded in natural gas~~rates and lower sales ~~and other.~~

~~Table~~ of ~~Contents~~

short term firm capacity on Citrus.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our intrastate~~ETP’s interstate transportation and storage segment increased due to the net impacts of the following:

An increase of $247 million associated with the Rover pipeline with increases of $336 million in revenues, $70 million in net operating expenses and $19 million in selling, general and administrative expenses; and

an aggregate increase 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 by

an increase of ~~$63~~$6 million in ~~natural gas sales and other (excluding net changes in unrealized gains and losses of $4 million)~~operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to higher ~~realized gains from pipeline optimization activity;~~maintenance project costs; and

a decrease of $11 million in storage margin (excluding net changes in unrealized gains and losses of $8 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below;

an increase of $10 million in retained fuel sales (excluding net changes in unrealized gains and losses of $4 million) primarily due to higher market prices. The average spot price at the Houston Ship Channel location increased 34% for the nine months ended September 30, 2017 compared to the same period last year;

an increase of $7 million in operating expenses primarily due to higher compression fuel expense of $6 million and higher maintenance and general expenses of $7 million, offset by lower allocated expenses of $3 million, lower capitalized overhead of $2 million and timing of project expenses of $1 million; and

~~an increase of $8~~$9 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to ~~two new joint venture pipelines placed in service in 2017;~~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 offset by lower legal fees on Citrus.

a decrease in transportation fees of $44 million due to renegotiated contracts resulting in lower billed volumes, offset by increased margin from optimization activity recorded in natural gas sales and other and an increase of $8 million due to new demand billings on our Houston Pipeline system.

~~Storage margin was comprised of the following:~~Midstream

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Withdrawals from storage natural gas inventory (MMBtu) —
11,547,500
(11,547,500 ) 23,092,500
33,205,000
(10,112,500 )
Realized margin on natural gas inventory transactions $ 5
$ (3 ) $ 8
$ 18
$ 33
$ (15 )
Fair value inventory adjustments (10 ) (4 ) (6 ) (46 ) 52
(98 )
Unrealized gains (losses) on derivatives 2
12
(10 ) 34
(74 ) 108
Margin recognized on natural gas inventory, including related derivatives (3 ) 5
(8 ) 6
11
(5 )
Revenues from fee-based storage 6
5
1
20
18
2
Total storage margin $ 3
$ 10
$ (7 ) $ 26
$ 29
$ (3 )



	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

~~The changes in storage margin were due primarily~~Volumes. For the three and nine months ended September 30, 2018 compared to the ~~movement~~same periods last year, gathered volumes and NGL production increased primarily due to increases in ~~market price of~~ the ~~physical storage gas~~North Texas, Permian and ~~the financial derivatives used to hedge that gas.~~Northeast regions, partially offset by smaller declines in other regions.

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Natural gas transported (MMBtu/d) 6,074,783
5,385,679
689,104
5,678,016
5,527,607
150,409
Natural gas sold (MMBtu/d) 19,012
19,478
(466 ) 17,659
19,398
(1,739 )
Revenues $ 224
$ 236
$ (12 ) $ 666
$ 729
$ (63 )
Operating expenses, excluding non-cash compensation, amortization and accretion expenses (79 ) (76 ) (3 ) (220 ) (223 ) 3
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (14 ) (13 ) (1 ) (33 ) (36 ) 3
Adjusted EBITDA related to unconsolidated affiliates 140
131
9
383
376
7
Other 2
—
2
4
2
2
Segment Adjusted EBITDA $ 273
$ 278
$ (5 ) $ 800
$ 848
$ (48 )

~~Volumes.~~ For the three months ended September 30, 2017 compared to the same period last year, transported volumes reflected increases of 157,060 MMBtu/d on the Trunkline pipeline as a result of increased backhaul deliveries, 153,401 MMBtu/d on the Tiger pipeline due to an increase in production in the Haynesville Shale, and 142,207 MMBtu/d on the Transwestern pipeline as a result of weather driven demand in the West and opportunities in the Texas intrastate market. The remainder of the increase was primarily due to the Rover pipeline, which was placed in partial service on August 31, 2017.

For the nine months ended September 30, 2017 compared to the same period last year, transported volumes increased due to the placement in partial service of the Rover pipeline effective August 31, 2017 and 59,305 MMBtu/d on the Tiger pipeline due to an increase in production in the Haynesville Shale and opportunities in the Texas intrastate market.



	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, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our interstate transportation and storage~~ETP’s midstream segment ~~decreased~~increased due to the net ~~effect~~impacts of the following:

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 ~~reservation revenues of $16 million on the Panhandle, Trunkline~~selling, general and ~~Transwestern pipelines and~~administrative expenses primarily due to a decrease of $3 million in ~~gas parking service~~merger and acquisition costs and a $3 million change in capitalized overhead; and

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

an increase of ~~customer demand driven by weak spreads and mild weather. In addition, revenues on the Tiger pipeline decreased $3~~$22 million ~~due to contract restructuring. These decreases were offset by $10 million of revenues from the placement in partial service of the Rover pipeline effective August 31, 2017; and~~

~~an increase~~ in operating expenses ~~of $3 million primarily~~ due to ~~higher ad valorem taxes resulting from higher valuations; offset by~~

~~an increase~~increases of $6 million in ~~income from unconsolidated joint ventures of $9~~materials, $5 million ~~primarily due to~~in outside services and $4 million in maintenance project costs, as well as a ~~legal settlement and lower operating expenses on Citrus.~~

$7 million change in capitalized overhead.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our interstate transportation and storage segment decreased due to the net effect of the following:~~

a decrease in reservation revenues of $41 million on the Panhandle, Trunkline and Transwestern pipelines and a decrease of $11 million in gas parking service related revenues on the Panhandle and Trunkline pipelines, primarily due to lack of customer demand driven by weak spreads and mild weather, decrease of $17 million in revenues on the Tiger pipeline due to contract restructuring, and a decrease of $4 million on the Sea Robin pipeline due to producer maintenance and production declines. The decreases above were offset by $10 million of revenues from the placement in partial service of the Rover pipeline effective August 31, 2017;

a decrease in operating expenses of $3 million primarily due to lower allocated costs of $7 million and lower lease storage expense of $3 million, partially offset by higher ad valorem taxes resulting from higher valuations; and

~~a decrease in selling, general and administrative expenses of $3 million due to refunds associated with legal fees, insurance premiums and franchise taxes; offset by~~

~~Table of Contents~~

an increase in income from unconsolidated joint ventures of $7 million primarily due to a legal settlement and lower operating expenses on Citrus, partially offset by lower earnings from Midcontinent Express.

~~Midstream~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Gathered volumes (MMBtu/d) 11,090,285
9,675,003
1,415,282
10,764,317
9,853,930
910,387
NGLs produced (Bbls/d) 449,454
420,877
28,577
442,190
440,124
2,066
Equity NGLs (Bbls/d) 27,185
34,341
(7,156 ) 26,936
31,847
(4,911 )
Revenues $ 1,765
$ 1,343
$ 422
$ 5,017
$ 3,765
$ 1,252
Cost of products sold 1,235
867
368
3,403
2,415
988
Segment margin 530
476
54
1,614
1,350
264
Unrealized (gains) losses on commodity risk management activities 1
—
1
(18 ) —
(18 )
Operating expenses, excluding non-cash compensation expense (157 ) (153 ) (4 ) (470 ) (453 ) (17 )
Selling, general and administrative expenses, excluding non-cash compensation expense (26 ) (17 ) (9 ) (60 ) (42 ) (18 )
Adjusted EBITDA related to unconsolidated affiliates 6
7
(1 ) 20
19
1
Other 2
1
1
2
1
1
Segment Adjusted EBITDA $ 356
$ 314
$ 42
$ 1,088
$ 875
$ 213

~~Volumes.~~ Gathered volumes and NGL production increased during the three and nine months ended September 30, 2017 compared to the same periods last year primarily due to recent acquisitions, including PennTex, and gains in the Permian and Northeast regions, partially offset by basin declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions.

~~Segment Margin. The components of our midstream segment margin were as follows:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Gathering and processing fee-based revenues $ 422
$ 391
$ 31
$ 1,264
$ 1,171
$ 93
Non fee-based contracts and processing 108
85
23
350
179
171
Total segment margin $ 530
$ 476
$ 54
$ 1,614
$ 1,350
$ 264

~~Segment Adjusted EBITDA.~~ ~~For the three months ended September 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our~~ETP’s midstream segment increased due to the net ~~effects of the following:~~

~~an increase of $24 million (excluding net changes in unrealized gains and losses of $1 million) in non-fee based margin due to higher crude oil and NGL prices;~~

an increase of $16 million in fee-based revenue due to minimum volume commitments in the South Texas region, as well as volume increases in the Permian and Northeast regions. These increases were partially offset by volume declines in South Texas, North Texas and the Mid-Continent/Panhandle regions; and

~~an increase of $15 million in fee-based revenue due to recent acquisitions, including PennTex; partially offset by~~

~~an increase of $4 million in operating expenses primarily due to recent acquisitions, including PennTex; and~~

~~an increase in selling, general and administrative expenses primarily due to an increase in shared services allocation.~~

~~Table of Contents~~

~~Segment Adjusted EBITDA.~~ ~~For the nine months ended September 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects~~impacts of the following:

an increase of ~~$113~~$68 million in ~~non-fee based~~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 ~~$38~~$47 million ~~(excluding net changes~~ in ~~unrealized gains and losses of $20 million) in non-fee based~~non-fee-based margin due to increased throughput volume ~~increases~~ in the ~~Permian, partially offset by declines in the South Texas,~~ North Texas and ~~Mid-Continent/Panhandle~~Permian regions;

an increase of ~~$36~~$5 million in ~~fee-based revenue~~Adjusted EBITDA related to unconsolidated affiliates due to ~~minimum volume commitments in the South Texas region, as well as volume increases in the Permian~~higher earnings from ETP’s Aqua, Mi Vida and ~~Northeast regions. These increases were partially offset by volume declines in the South Texas, North Texas and the Mid-Continent/Panhandle regions;~~Ranch joint ventures; and

~~an increase~~a decrease of ~~$57~~$1 million in ~~fee-based revenue~~selling, general and administrative expenses primarily due to ~~recent acquisitions, including PennTex;~~lower office expenses; partially offset by

an increase of ~~$17~~$42 million in operating expenses primarily due to ~~recent acquisitions, including PennTex; and~~

~~an increase~~increases of ~~$18~~$13 million in ~~general and administrative expenses primarily due to a decrease of~~outside services, $12 million in materials, $8 million in employee costs and $4 million in maintenance project costs as well as a $3 million change in capitalized ~~overhead, a $13 million increase in shared services allocation and $6 million additional costs from the PennTex acquisition. These increases were partially offset by a favorable impact~~overhead.

Table of ~~$12 million from the adjustment of certain reserves that had previously been recorded in connection with contingent matters.~~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,
	2017			2016			Change			2017			2016			Change			2018			2017			Change			2018			2017			Change
NGL transportation volumes (MBbls/d)	836			766			70			827			741			86			1,086			836			250			997			829			168
Refined products transportation volumes (MBbls/d)	612			611			1			626			573			53			627			612			15			628			626			2
NGL and refined products terminal volumes (MBbls/d)	782			822			(40		)	793			782			11			858			782			76			784			780			4
NGL fractionation volumes (MBbls/d)	390			338			52			418			350			68			567			390			177			505			418			87
Revenues	$	2,070		$	1,545		$	525		$	6,115		$	4,329		$	1,786		$	3,063		$	2,070		$	993		$	8,177		$	6,115		$	2,062
Cost of products sold	1,582			1,061			521			4,552			2,972			1,580			2,429			1,587			842			6,356			4,557			1,799
Segment margin	488			484			4			1,563			1,357			206			634			483			151			1,821			1,558			263
Unrealized losses on commodity risk management activities	56			21			35			2			53			(51		)	26			56			(30		)	26			2			24
Operating expenses, excluding non-cash compensation expense	(105		)	(109		)	4			(358		)	(319		)	(39		)	(168		)	(106		)	(62		)	(448		)	(358		)	(90		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(13		)	(12		)	(1		)	(49		)	(41		)	(8		)	(17		)	(13		)	(4		)	(52		)	(49		)	(3		)
Adjusted EBITDA related to unconsolidated affiliates	19			21			(2		)	54			53			1			23			19			4			63			54			9
Inventory valuation adjustments	(22		)	(22		)	—			(17		)	(31		)	14
Other	—			—			—			1			—			1			—			—			—			—			1			(1		)
Segment Adjusted EBITDA	$	423		$	383		$	40		$	1,196		$	1,072		$	124		$	498		$	439		$	59		$	1,410		$	1,208		$	202

Volumes. For the three and nine months ended September 30, ~~2017~~2018 compared to the same periods last year, NGL transportation volumes increased primarily from the Permian region resulting from a ramp up in production from existing customers, higher throughput volumes on Mariner West driven by end user facility constraints in the prior period and ~~refined~~higher throughput from Mariner South.

Refined products transportation volumes increased ~~in the major producing regions, including the Permian, Southeast Texas, Louisiana, Eagle Ford and North Texas.~~

~~NGL and refined products terminal volumes decreased~~ for the three and nine months ended September 30, ~~2017~~2018 compared to the same periods last year primarily due to higher throughput volumes from the ~~sale of one of our refined product terminals in April 2017.~~ Northeast and Southwest regions, partially offset by decreased throughput volumes from the Midwest region.

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, ~~2017~~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 ~~our Marcus Hook Industrial Complex from the Northeast producing regions.~~ETP’s Eagle Point terminal and lower volumes at ETP’s refined products marketing terminals.

~~Table of Contents~~

Average ~~daily~~ fractionated volumes at ETP’s Mont Belvieu, Texas fractionation facility increased ~~17%~~45% and ~~23%~~21% for the three and nine months ended September 30, ~~2017,~~2018, respectively, compared to the same periods last year primarily due to the commissioning of ~~our fourth~~ETP’s fifth fractionator ~~at Mont Belvieu, Texas,~~ in ~~October 2016, which has a capacity of 120,000 Bbls/d,~~July 2018 as well as increased ~~producer~~ volumes ~~as mentioned above.~~from Permian producers.

Table of Contents

Segment Margin. The components of ~~our~~ETP’s 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,
	2017			2016		Change			2017		2016		Change		2018			2017			Change			2018			2017			Change
Fractionators and Refinery services margin	$	117		$	103	$	14		$	352	$	296	$	56
Fractionators and refinery services margin															$	162		$	115		$	47		$	424		$	352		$	72
Transportation margin	246			226		20			720		629		91		322			246			76			878			720			158
Storage margin	50			50		—			160		148		12		50			50			—			154			160			(6		)
Terminal Services margin	90			83		7			258		239		19
Terminal services margin															109			90			19			294			258			36
Marketing margin	(15		)	22		(37		)	73		45		28		17			38			(21		)	97			70			27
Unrealized losses on commodity risk management activities															(26		)	(56		)	30			(26		)	(2		)	(24		)
Total segment margin	$	488		$	484	$	4		$	1,563	$	1,357	$	206	$	634		$	483		$	151		$	1,821		$	1,558		$	263

Segment Adjusted EBITDA. For the three months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our~~ETP’s NGL and refined products transportation and services segment increased due to the net ~~impact~~impacts of the following:

an increase of $76 million in transportation margin ~~of $20~~due to a $63 million ~~primarily~~increase resulting from higher producer volumes from the Permian region on ETP’s Texas NGL pipelines, an $11 million increase due to higher throughput volumes on ~~our Texas NGL pipelines~~Mariner West driven by end user facility constraints in the prior period, an $8 million increase due to higher throughput volumes from the Eagle Ford and ~~our~~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 ~~system;~~

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;

an increase of $47 million in fractionation and refinery services margin ~~of $13 million (excluding net changes in unrealized gains and losses of $1 million) primarily~~ due to a $40 million increase resulting from the commissioning of ETP’s fifth fractionator in July 2018 and higher NGL volumes from ~~most major producing regions,~~the Permian region feeding ETP’s Mont Belvieu fractionation facility, a $4 million increase from Mariner South as ~~noted above;~~

more cargoes were loaded due to increased demand for export and a $3 million increase from blending gains as a result of improved market pricing; and

an increase of $19 million in terminal services margin due to a $9 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 exports 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; 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 ~~terminal volumes from the Mariner NGL projects;~~overhead allocations, $6 million due to environmental reserves and

$5 million due to ad valorem tax expense; and

a decrease of $4$21 million in ~~operating expenses~~marketing margin primarily due to a ~~legal settlement~~$13 million decrease in optimization gains from ETP’s Mont Belvieu marketing activities, a $4 million decrease from sales of ~~$8 million~~propane and other products at ETP’s Marcus Hook Industrial Complex and a ~~quarterly ad valorem tax true-up of $1 million; partially offset by~~

$2 million decrease from ETP’s butane blending operations resulting from a decrease ~~of $1 million~~ in ~~marketing margin (excluding net changes in unrealized gains and losses of $36 million) primarily due to the timing of the recognition of margin from optimization activities; and~~

~~an increase of $1 million in selling, general and administrative expenses due to higher allocations and lower capitalized overhead resulting from reduced capital spending.~~blending volumes.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our~~ETP’s NGL and refined products transportation and services segment increased due to the net ~~impact~~impacts of the following:

an increase ~~in storage margin~~ of ~~$12~~$158 million ~~primarily due to increased volumes from our Mont Belvieu fractionators;~~

~~an increase~~ in transportation margin ~~of $91~~due to a $141 million ~~primarily~~increase resulting from higher producer volumes from the Permian region on ETP’s Texas NGL pipelines, a $22 million increase due to higher throughput volumes on ~~our Texas NGL pipelines~~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 ~~our Mariner East system;~~

anfractionation margins in the second quarter of 2018, a $4 million increase ~~in fractionation and refinery services margin of $55 million (excluding net changes in unrealized gains and losses of $1 million) primarily~~ due to higher ~~NGL~~throughput volumes from ~~most major producing regions, as noted above;~~

anthe Barnett region, a $4 million increase ~~in terminal services margin of $19 million~~ due to higher ~~terminal~~throughput volumes from ~~the Mariner NGL projects;~~ETP’s Northeast and

an Southwest refined product systems and a $4 million increase of $22 million in marketing margin (excluding net changes in unrealized gains and losses of $50 million) primarily due to the timing of the recognition of margin from optimization activities; partially offset by

an increase of $39 million in operating expenses primarily due to increased utilities costs associated with our fourth fractionator at Mont Belvieu and the Mariner project ramp up at the Marcus Hook Industrial Complex of $15 million, higher ad valorem tax expenses of $11 million (primarily from our Lone Star Express pipeline beginning service in 2016), higher employee expenses associated with assets placed in service of $5 million and project related service expenses of $5 million; and

~~an increase of $8 million in selling, general and administrative expenses~~ due to higher ~~allocations and lower capitalized overhead~~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 ~~reduced capital spending.~~lower throughput on Mariner

4958

Table of Contents

East 1 due to system downtime in 2018, a $10 million decrease due to lower transported volumes from the Southeast Texas region and a $2 million decrease resulting from the timing of deficiency revenue recognition;

an increase of $72 million in fractionation and refinery services margin due to a $63 million increase resulting from the commissioning of ETP’s fifth fractionator 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. These increases were partially offset by an $11 million decrease resulting from a reclassification between ETP’s 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 exports 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 $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,
	2017			2016			Change			2017			2016			Change			2018			2017			Change			2018			2017			Change
Crude Transportation Volumes (MBbls/d)	3,758			2,686			1,072			3,401			2,500			901
Crude Terminals Volumes (MBbls/d)	1,923			1,559			364			1,877			1,524			353
Crude transportation volumes (MBbls/d)																			4,276			3,773			503			4,119			3,425			694
Crude terminals volumes (MBbls/d)																			2,134			1,923			211			2,060			1,884			176
Revenues	$	2,725		$	1,856		$	869		$	7,765		$	5,146		$	2,619		$	4,438		$	2,725		$	1,713		$	12,986		$	7,765		$	5,221
Cost of products sold	2,137			1,590			547			6,563			4,294			2,269			3,494			2,177			1,317			11,032			6,571			4,461
Segment margin	588			266			322			1,202			852			350			944			548			396			1,954			1,194			760
Unrealized gains on commodity risk management activities	(1		)	—			(1		)	(3		)	—			(3		)
Unrealized (gains) losses on commodity risk management activities																			(118		)	(1		)	(117		)	187			(3		)	190
Operating expenses, excluding non-cash compensation expense	(119		)	(71		)	(48		)	(305		)	(185		)	(120		)	(126		)	(119		)	(7		)	(397		)	(305		)	(92		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(13		)	(16		)	3			(62		)	(44		)	(18		)	(22		)	(13		)	(9		)	(64		)	(62		)	(2		)
Adjusted EBITDA related to unconsolidated affiliates	5			5			—			11			10			1			4			5			(1		)	14			11			3
Inventory valuation adjustments	(64		)	(15		)	(49		)	(13		)	(112		)	99
Segment Adjusted EBITDA	$	396		$	169		$	227		$	830		$	521		$	309		$	682		$	420		$	262		$	1,694		$	835		$	859

Volumes. For the three and nine months ended September 30, 2018 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 crude terminal from the Bakken pipeline and from increased West Texas production.

Table of Contents

Segment Adjusted EBITDA. For the three months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our~~ETP’s crude oil transportation and services segment increased due to the net impacts of the following:

an increase of ~~$194~~$279 million in segment margin (excluding unrealized losses on commodity risk management activities) due to the following: a $131 million increase resulting from higher throughput, primarily from ETP’s Bakken pipeline and from Permian producers on existing pipeline assets, as well as a $30 million increase resulting primarily from placing ~~our Bakken Pipeline~~ETP’s Permian Express 3 pipeline in service in the ~~second~~fourth quarter of ~~2017, as well as the acquisition~~2017; a $108 million increase (excluding a net change of a$117 million in unrealized gains and losses) from ETP’s crude oil ~~gathering system in~~acquisition and marketing business primarily resulting from more favorable market price differentials between the West ~~Texas;~~

anTexas and Gulf Coast markets; and a $10 million increase ~~of $28 million~~ from ~~existing assets due to increased volumes throughout the system;~~higher throughput and

~~an increase of $18 million due to the impact of LIFO accounting;~~ ship loading fees at ETP’s Nederland terminal; partially offset by

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

~~additional~~an increase of $7 million in operating ~~expense as~~expenses due to a ~~result of~~$5 million increase due to higher throughput related expenses on existing assets and a $2 million increase from placing ~~other new projects~~ETP’s Permian Express 3 pipeline in service ~~and costs associated with increased volumes on our system.~~

in the fourth quarter of 2017.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our~~ETP’s crude oil transportation and services segment increased due to the net impacts of the following:

an increase of ~~$389~~$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 ~~our~~ETP’s Bakken ~~Pipeline~~pipeline in service in the second quarter of ~~2017, as well as the acquisition~~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 a$190 million in unrealized gains and losses) from ETP’s crude oil ~~gathering system in~~acquisition and marketing business primarily resulting from more favorable market price differentials between the West ~~Texas;~~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 ~~$11~~$3 million ~~from existing assets~~in Adjusted EBITDA related to unconsolidated affiliates due to increased ~~volumes throughout the system;~~jet fuel sales from ETP’s joint ventures; partially offset by

~~a decrease~~an increase of ~~$29~~$92 million in operating expenses due to ~~the impact of LIFO accounting. This unfavorable LIFO impact is expected to be reversed in future periods as commodity prices fall or the inventory positions are liquidated; and~~

~~additional operating expense as~~ a ~~result of~~$37 million increase primarily resulting from placing ~~other new projects~~ETP’s Bakken pipeline in service in the second quarter of 2017; a $36 million increase to throughput related costs on existing assets; a $19 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; a $7 million increase in overhead allocations; and ~~costs associated with increased volumes on our system.~~a $4 million increase from ad valorem taxes; partially offset by an $11 million decrease in insurance and environmental related expenses.

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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~~All Other~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Revenues $ 683
$ 956
$ (273 ) $ 2,249
$ 2,521
$ (272 )
Cost of products sold 571
877
(306 ) 1,959
2,263
(304 )
Segment margin 112
79
33
290
258
32
Unrealized (gains) losses on commodity risk management activities 3
1
2
(14 ) 19
(33 )
Operating expenses, excluding non-cash compensation expense (34 ) (20 ) (14 ) (86 ) (57 ) (29 )
Selling, general and administrative expenses, excluding non-cash compensation expense (34 ) (14 ) (20 ) (82 ) (60 ) (22 )
Adjusted EBITDA related to unconsolidated affiliates 88
63
25
244
209
35
Other and eliminations (2 ) 4
(6 ) 11
26
(15 )
Segment Adjusted EBITDA $ 133
$ 113
$ 20
$ 363
$ 395
$ (32 )

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

~~our~~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;~~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;

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

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;

a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETP’s 33% interest in PES ~~comprising 33% of PES' outstanding common units;~~was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETP holds an approximately 8% interest in PES and

no longer reflects PES as an affiliate; and

~~our~~ETP’s investment in ~~Coal Handling, an entity that owns and operates end-user~~ coal handling facilities.

Segment Adjusted EBITDA. For the three months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our~~ETP’s all other segment ~~increased primarily~~decreased due to the net ~~impact~~impacts of the following:

~~an increase~~a decrease of ~~$25~~$16 million in Adjusted EBITDA related to unconsolidated affiliates ~~reflecting~~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 ~~$34~~$12 million in Adjusted EBITDA related to unconsolidated affiliates from ~~our~~ETP’s investment in PES ~~offset by a decrease~~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 ~~$9 million from our investment in Sunoco LP;~~

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

~~an increase~~a decrease of $4$3 million primarily due to lower margin from ~~our~~ETP’s compression ~~operations; partially offset by~~

~~an increase of $11 million in transaction related expenses; and~~

~~an increase of $9 million in operating expenses related to an~~ equipment ~~lease buyout.~~

business.

Segment Adjusted EBITDA. For the nine months ended September 30, ~~2017~~2018 compared to the same period last year, Segment Adjusted EBITDA related to ~~our~~ETP’s all other segment decreased ~~primarily~~ due to the net ~~impact~~impacts of the following:

a decrease of ~~$66 million related to the termination of management fees paid by ETE that ended in 2016; and~~

~~an increase of $39 million in transaction related expenses; partially offset by~~

~~an increase of $35~~$85 million in Adjusted EBITDA related to unconsolidated affiliates ~~primarily comprising increases~~from ETP’s investment in Sunoco LP resulting from ETP’s lower ownership in Sunoco LP and lower operating results of ~~$29~~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 ~~our~~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 $3

a decrease of $21 million ~~from our~~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 ~~Sunoco LP;~~USAC held by ETP subsequent to the CDM Contribution; partially offset by

an increase of ~~$15~~$10 million in Adjusted EBITDA primarily due to lower transport fees of $6 million resulting from ~~commodity trading activities;~~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 ~~expenses related to our compression operations.~~margin from depressed gas prices in West Texas.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

ETP’s ability to satisfy its obligations and pay distributions to its ~~Unitholders~~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 to be within the following ranges (excluding capital expenditures related to the businesses contributed to ETP in connection with the ETE-ETP Merger in October 2018):



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


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

For ~~the year ending December 31, 2017,~~2019, we expect to spend approximately $4.1 billion on capital expenditure funding, net of $1.0 billion financed at the asset level and net an approximately $1.4 billion reduction related to the sale of a portion of our interest in the Rover pipeline project. For 2018, we expect to spend approximately $3$5 billion on organic growth projects.

The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we include 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 units, dropdown proceeds or the monetization of non-core assets or a combination thereof.

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 include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and net changes in operating assets and ~~liabilities.~~liabilities (net of effects of acquisitions and deconsolidations). 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 acquisitions~~ of assets, while changes in non-cash ~~unit-based~~ 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 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, ~~2017~~2018 compared to nine months ended September 30, ~~2016.~~2017. Cash provided by operating activities during ~~2017~~2018 was ~~$3.34~~$5.10 billion compared to ~~$2.47~~$3.34 billion for ~~2016~~2017 and net income was ~~$1.42~~$2.84 billion and ~~$986 million~~$1.40 billion for ~~2017~~2018 and ~~2016,~~2017, respectively. The difference between net income and cash provided by operating activities for the nine months ended September 30, ~~2017~~2018 primarily consisted of net changes in operating assets and liabilities (net of ~~$185~~effects of acquisitions and deconsolidations) of $451 million and other non-cash items totaling ~~$1.44~~$1.51 billion.

The non-cash activity in ~~2017~~2018 and ~~2016~~2017 consisted primarily of depreciation, depletion and amortization of $1.83 billion and $1.71 billion, respectively, and ~~$1.47 billion, respectively,~~ non-cash compensation expense of $61 million and $57 million, respectively. Unconsolidated affiliate activity in 2018 and ~~$60 million, respectively, and~~2017 consisted of equity in earnings of ~~unconsolidated affiliates of~~$147 million and $139 million, respectively, and ~~$260~~distributions received of $328 million and $319 million, respectively. Non-cash activity in ~~2017~~2018 also included ~~deferred income taxes~~a gain on the sale of $1Sunoco LP units of $172 million and ~~inventory valuation adjustments~~a loss on the deconsolidation of ~~$30 million. Non-cash activity in 2016 also included impairment~~CDM of ~~investment in an unconsolidated affiliate of $308~~$86 million.

Cash paid for interest, net of interest capitalized, was ~~$1.03 billion~~$996 million and ~~$1.10~~$1.01 billion for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively.

Capitalized interest was ~~$177~~$221 million and ~~$148~~$211 million for the nine months ended September 30, 2018 and 2017, ~~and 2016,~~ respectively.

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Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. 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, ~~2017~~2018 compared to nine months ended September 30, ~~2016.~~2017. Cash used in investing activities during ~~2017~~2018 was ~~$4.69~~$3.07 billion compared to ~~$3.64~~$4.69 billion ~~for 2016.~~in 2017. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for ~~2017~~2018 were ~~$6.06~~$4.87 billion compared to ~~$5.74~~$6.06 billion for ~~2016.~~2017. Additional detail related to our capital expenditures is provided in the table below. During 2018, we received $1.23 billion in cash related to 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 noncontrolling interest and paid $264 million in cash for all other acquisitions. ~~During 2016, we received $2.20 billion in cash related to the contribution of our Sunoco, Inc. retail business to Sunoco LP.~~

The following is a summary of capital expenditures (net of contributions in aid of construction costs) for the nine months ended September 30, ~~2017:~~2018:


	Capital Expenditures Recorded During Period						Capital Expenditures Recorded During Period
	Growth		Maintenance		Total		Growth		Maintenance		Total
Intrastate transportation and storage	$	34	$	22	$	56	$	233	$	37	$	270
Interstate transportation and storage	1,704		50		1,754		470		73		543
Midstream	914		76		990		731		113		844
NGL and refined products transportation and services	2,106		53		2,159		1,494		44		1,538
Crude oil transportation and services	331		36		367		333		33		366
All other (including eliminations)	128		49		177		43		42		85
Total capital expenditures	$	5,217	$	286	$	5,503	$	3,304	$	342	$	3,646

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, ~~2017~~2018 compared to nine months ended September 30, ~~2016.~~2017. Cash used in financing activities during 2018 was $1.96 billion compared to provided by financing activities ~~during 2017 was~~of $1.37 billion ~~compared to $1.03 billion~~ for ~~2016.~~2017. In ~~2017~~2018 and ~~2016,~~2017, we received net proceeds from ~~Common Unit~~ETP common unit offerings of $58 million and $2.16 billion, ~~and $794 million,~~ respectively. In ~~2016, our subsidiaries~~2018, we received ~~$1.31 billion in net proceeds~~$867 million from ~~the issuance of common units.~~preferred unit offerings. During ~~2017,~~2018, we had a net increase in our debt level of ~~$1.24 billion~~$410 million compared to a net increase of ~~$1.76~~$1.24 billion for ~~2016.~~2017. We have paid distributions of $3.14 billion to ETP’s unitholders in 2018 compared to $2.54 billion ~~to our partners~~ in ~~2017 compared to $2.67 billion in 2016.~~2017. We have also paid distributions of ~~$306~~$536 million to noncontrolling interests in ~~2017~~2018 compared to ~~$334~~$306 million in ~~2016.~~2017. In addition, we have received capital contributions of ~~$919~~$438 million in cash from noncontrolling interests in ~~2017~~2018 compared

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to ~~$187~~$919 million in ~~2016.~~2017. During 2018, we also repurchased ETP common units for cash of $24 million and incurred debt issuance costs of $42 million. During 2017, we also repurchased our outstanding Legacy ETP Preferred Units for 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 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 assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).

$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.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
ETP Senior Notes(1)	$	20,540		$	19,440		$	28,755		$	27,005
Transwestern Senior Notes	575			657			575			575
Panhandle Senior Notes	1,085			1,085			386			785
Sunoco, Inc. Senior Notes	65			465
Sunoco Logistics Senior Notes	7,600			5,350
Credit facilities and commercial paper:
ETLP $3.75 billion Revolving Credit Facility due November 2019⁽¹⁾	2,056			2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020⁽²⁾	35			1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017⁽³⁾	—			630
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
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			1,100			2,500			2,500
PennTex $275 million Revolving Credit Facility due December 2019	—			168
Other long-term debt	5			30			4			5
Unamortized premiums, net of discounts and fair value adjustments	76			116			35			61
Deferred debt issuance costs	(197		)	(180		)	(188		)	(179		)
Total debt	34,340			32,930			33,847			33,094
Less: current maturities of long-term debt	710			1,189			2,649			407
Long-term debt, less current maturities	$	33,630		$	31,741		$	31,198		$	32,687

⁽¹⁾

Includes ~~$2.06 billion~~$400 million aggregate principal amount of 9.70% senior notes due March 15, 2019 and ~~$777~~$450 million aggregate principal amount of ~~commercial paper outstanding at~~9.00% senior notes due April 15, 2019 that were classified as long-term as of September 30, ~~2017~~2018 as management has the intent and ~~December 31, 2016, respectively.~~ability to refinance the borrowings on a long-term basis.


⁽²⁾	Includes ~~$50 million~~$1.57 billion and $2.01 billion of commercial paper outstanding at September 30, 2018 and December 31, ~~2016.~~


⁽³⁾	Sunoco Logistics’ $1.00 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics had the ability and intent to refinance such borrowings on a long-term basis. This 364-Day Credit Facility was terminated and repaid in May 2017.2017, respectively.

ETP Senior Notes Offering and Redemption

In ~~October 2017,~~June 2018, ETP issued the ~~Partnership redeemed all of the outstanding $500~~following senior notes:

$500 million aggregate principal amount of ~~ETLP’s 6.50%~~4.20% senior notes due ~~July 2021 and all~~2023;

$1.00 billion aggregate principal amount of ~~the outstanding $700~~4.95% senior notes due 2028;

$500 million aggregate principal amount of ~~ETLP’s 5.50%~~5.80% senior notes due ~~April 2023. The~~2038; and

$1.00 billion aggregate principal amount ~~paid to redeem these~~of 6.00% senior notes ~~including call premiums, was approximately $1.23 billion.~~

~~ETP Senior Notes Offering~~ due 2048.

~~In September 2017,~~The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually.

The senior notes rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETP 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 ~~subsidiary~~senior unsecured basis so long as it guarantees any of ~~ETP, issued $750 million aggregate principal amount~~our other long-term debt. The guarantee for each series of ~~4.00%~~notes ranks equally in right of payment with all of the existing and future senior ~~notes due 2027 and $1.50 billion aggregate principal amount~~debt of ~~5.40%~~Sunoco Logistics Partners Operations L.P., including its senior ~~notes due 2047.~~ notes.

The ~~$2.22~~$2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETP’s revolving credit facility, for general partnership purposes and to redeem all of the ~~$500~~following senior notes:

ETP’s $650 million aggregate principal amount of ~~ETLP’s 6.5%~~2.50% senior notes due ~~2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility (described below)~~June 15, 2018;

Panhandle’s $400 million aggregate principal amount of 7.00% senior notes due June 15, 2018; and ~~for general partnership purposes.~~

~~Credit Facilities and Commercial Paper~~

~~ETLP Credit Facility~~ETP’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018.

The ~~ETLP Credit Facility allows for borrowings of up~~aggregate amount paid to $3.75 billion and matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of whichredeem these notes was ~~commercial paper.~~approximately $1.65 billion.

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~~Sunoco Logistics~~ Credit Facilities and Commercial Paper

ETP ~~maintains the Sunoco Logistics $2.50 billion unsecured~~Five-Year Credit Facility

ETP’s revolving credit facility (the ~~“Sunoco Logistics~~“ETP Five-Year Credit Facility”)~~, which matures~~ previously allowed for unsecured borrowings up to $4.00 billion and matured in ~~March 2020.~~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 December 1, 2023. The ~~Sunoco Logistics~~ETP Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to ~~$3.25~~$6.00 billion under certain conditions.

ETP 364-Day Facility

ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) previously allowed for unsecured borrowings up to $1.00 billion and matured 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, the ETP 364-Day Facility had no outstanding borrowings.

In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.

Bakken Credit Facility

In August 2016, ~~Energy Transfer Partners, L.P., Sunoco Logistics~~ETP and Phillips 66 completed project-level financing of the Bakken ~~Pipeline.~~pipeline. The $2.50 billion credit facility ~~provides substantially all of the remaining capital necessary to complete the projects.~~matures in August 2019 (the “Bakken Credit Facility”). As of September 30, ~~2017,~~2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings, all of which has been reflected in current maturities of long-term debt on the Partnership’s consolidated balance sheet included in “Item 1. Financial Statements.” The weighted average interest rate on the total amount outstanding as of September 30, 2018 was ~~outstanding under this credit facility.~~

~~PennTex Revolving Credit Facility~~

Covenants Related to Our Credit Agreements

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, ~~2017.~~2018.

CASH DISTRIBUTIONS

~~Following the Sunoco Logistics Merger, cash distributions are~~Distributions on common units declared and paid ~~in accordance with~~by the ~~Partnership’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement~~Partnership subsequent to December 31, 2017 but prior to the ~~Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end~~closing of the ~~quarter, less reserves established by the general partner~~ETE-ETP Merger as discussed in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

~~If cash distributions exceed~~ $0.0833 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

~~The following table shows the target distribution levels and distribution “splits” between the general partner and the holders~~Note 1 of the Partnership’s ~~common units:~~consolidated financial statements included in “Item 1. Financial Statements,” were as follows:

⁽¹⁾~~Includes general partner and limited partner interests, based on the proportionate ownership of each.~~

~~For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.~~



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

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~~Following are distributions~~Distributions on ETP’s preferred units declared and/or paid by the Partnership subsequent to ~~the Sunoco Logistics Merger:~~December 31, 2017 were as follows:

~~The total amounts of distributions declared for the periods presented (all from Available Cash from our operating surplus and are shown in the period with respect to which they relate):~~

Nine Months Ended
September 30,
2017 2016
ETP Energy Transfer Partners, L.P. Sunoco Logistics
Limited Partners:
Common Units held by public $ 1,794
$ 1,607
$ 353
Common Units held by ETP —
—
100
Common Units held by ETE 45
8
—
Class H Units held by ETE —
263
—
General Partner interest 12
24
11
Incentive distributions held by ETE 1,204
1,012
289
IDR relinquishments (482 ) (271 ) (8 )
Total distributions declared to partners $ 2,573
$ 2,643
$ 745



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

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. See Note 1 in “Item 1. Financial Statements” for information regarding recent changes to the Partnership’s critical accounting policies ~~have not changed subsequent to those reported in Exhibit 99.3 to its Form 8-K filed on May 8, 2017. The following information is provided to supplement the Form 8-K disclosures specifically~~ related to ~~impairment of long-lived assets and goodwill.~~revenue recognition.

~~Impairment of Long-Lived Assets and Goodwill.~~ Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.RECENT ACCOUNTING PRONOUNCEMENTS

In order to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations.

The Partnership determined the fair value of its reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the

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overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

One key assumption for the measurement of goodwill impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks describedSee Note 1 in “Item ~~1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used~~1. Financial Statements” included in this Quarterly Report for ~~goodwill impairment testing, and significant changes in fair value estimates could occur in a given period.~~

~~The goodwill impairments recorded by the Partnership during the years ended December 31, 2016 and 2015 represented all of the goodwill within the respective reporting units.~~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 ~~Exhibit 99.3 to~~ the Partnership’s ~~Current~~Annual Report on Form ~~8-K~~10-K for the year ended December 31, 2017 filed with the SEC on ~~May 8, 2017,~~February 23, 2018, 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, ~~2016.~~2017. Since December 31, ~~2016~~2017, 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. ~~Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power, and barrels for natural gas liquids, crude and refined products.~~ Dollar amounts are presented in millions.


	September 30, 2017							December 31, 2016							September 30, 2018							December 31, 2017
	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 (MMBtu):
Natural Gas (BBtu):
Fixed Swaps/Futures	1,297,500		$	—		$	—	(682,500	)	$	—		$	—	358		$	—		$	—	1,078		$	—		$	—
Basis Swaps IFERC/NYMEX⁽¹⁾	(15,810,000	)	(4		)	—		2,242,500		(1		)	—		69,685		8			1		48,510		2			1
Options – Puts	13,000,000		—			—		—		—			—		(17,273	)	—			—		13,000		—			—
Power (Megawatt):
Forwards	665,040		—			2		391,880		(1		)	1		429,720		6			—		435,960		1			1
Futures	(213,840	)	—			1		109,564		—			—		309,123		(1		)	1		(25,760	)	—			—
Options – Puts	(280,800	)	1			2		(50,400	)	—			—		157,435		1			—		(153,600	)	—			1
Options – Calls	545,600		—			1		186,400		1			—		321,240		��			—		137,600		—			—
Crude (Bbls) – Futures	(160,000	)	1			1		(617,000	)	(4		)	6
Crude (MBbls) – Futures															—		—			—		—		1			—
(Non-Trading)
Natural Gas (MMBtu):
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	67,500		(3		)	2		10,750,000		2			—		(7,705	)	(45		)	14		4,650		(13		)	4
Swing Swaps IFERC	91,897,500		(1		)	—		(5,662,500	)	(1		)	1		69,145		—			2		87,253		(2		)	1
Fixed Swaps/Futures	(20,220,000	)	1			7		(52,652,500	)	(27		)	19		(1,784	)	1			1		(4,700	)	(1		)	2
Forward Physical Contracts	(140,937,993	)	3			43		(22,492,489	)	1			8		(54,151	)	5			—		(145,105	)	6			41
Natural Gas Liquid (Bbls) – Forwards/Swaps	(8,747,200	)	(48		)	79		(5,786,627	)	(40		)	35
Refined Products (Bbls) – Futures	(701,000	)	—			9		(2,240,000	)	(16		)	17
NGL (MBbls) – Forwards/Swaps															(4,997	)	(45		)	20		(2,493	)	5			16
Crude (MBbls) – Forwards/Swaps															35,280		(190		)	152		9,172		(4		)	9
Refined Products (MBbls) – Futures															(1,521	)	(5		)	9		(3,783	)	(25		)	4
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2			—		(36,370,000	)	2			1		(21,475	)	(4		)	—		(39,770	)	(2		)	—
Fixed Swaps/Futures	(41,102,500	)	5			12		(36,370,000	)	(26		)	14		(21,475	)	(2		)	7		(39,770	)	14			11


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

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial 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.

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Interest Rate Risk

As of September 30, ~~2017~~2018, we had ~~$5.20~~$4.88 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of ~~$52~~$49 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
Term	Type⁽¹⁾	September 30, 2017		December 31, 2016		Type⁽¹⁾	September 30, 2018		December 31, 2017
July 2017⁽²⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200		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 3.64% and receive a floating rate	300		200		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		—		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		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		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.

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 ~~$237~~$239 million as of September 30, ~~2017.~~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 ~~$19~~$4 million. 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, ~~2017~~2018 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

As a result of the Sunoco Logistics Merger, which was completed in April 2017, our internal control over financial reporting now includes the controls of Energy Transfer, LP (formerly named “Energy Transfer Partners, L.P.”). The internal control over financial

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reporting of Energy Transfer, LP was evaluated by Energy Transfer, LP’s management (which is now the Partnership’s management) as of December 31, 2016 under the same framework that the Partnership’s internal control over financial reporting was evaluated, and Energy Transfer, LP’s management concluded that its internal control over financial reporting was effective as of December 31, 2016.

There have been no ~~other~~ changes in our internal controls over financial reporting (as defined in Rule 13(a)–15(f) or Rule 15d–15(f) of the Exchange Act) during the three months ended September 30, ~~2017~~2018 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 ~~Exhibit 99.3 to~~ our ~~Current~~Annual Report on Form ~~8-K~~10-K filed with the SEC on ~~May 8, 2017~~February 23, 2018 and Note 1110 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer ~~Partners,~~Operating, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, ~~2017~~.2018.

~~The EPA has brought a~~Additionally, we have received notices of violations and potential fines under various federal, ~~court action against SPLP~~state and ~~Mid-Valley for violations~~local provisions relating to the discharge of materials into the environment or protection of the ~~Clean Water Act (“CWA”). The United States’ complaint alleges~~environment. While we believe that ~~SPLP and Mid-Valley violated Sections 311(b)(7)(A) and 301(a)~~even if any one or more of the ~~CWA when,~~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 ~~three separate releases, pipelines operated~~the period covered by ~~SPLP and owned~~this report, (ii) that became a reportable event during the period covered by ~~SPLP~~this report, or ~~Mid-Valley Pipeline Company discharged oil. See 33 U.S.C. §§ 1311(a) and 1321(b)(7)(A). In particular,~~(iii) for which there has been a material development during the three releases at issue occurred (1) on February 23, 2013, in Tyler County, Texas, when a reported 550 barrels of oil were discharged; (2) on October 13, 2014, in Caddo Parish, Louisiana, when a reported 4,509 barrels of oil were discharged; and (3) onperiod covered by this report.

On January 20, 2015, in Grant County, Oklahoma, when a reported 40 barrels of oil were discharged. Potential fines from the DOJ are $7 million and from the State of Louisiana are approximately $1 million. The Partnership is currently in discussions to resolve these matters.

~~Mont Belvieu received~~18, 2018, PHMSA issued a Notice of ~~Enforcement~~Probable Violation and a Proposed Compliance Order in connection with alleged violations 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, ETC Northeast Pipeline LLC (“~~NOE”~~ETC Northeast”) entered into a Consent Order and Agreement with ~~an Agreed Order from~~ the ~~Texas Commission on Environmental Quality~~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 ~~a pending~~paid the settlement ~~for $0.01 million. The NOE was for~~amount and continues to monitor the ~~two violations.~~construction site and work with the landowner to resolve any remaining issues related to the restoration of the construction site.

On June 29, 2018, Luminant Energy Company, LLC (“Luminant”) filed informal and formal complaints against Energy Transfer ~~Company~~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. ETF 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 ~~LLC~~ received ~~a settlement agreement and a stipulated final compliance order from~~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 (“NMED”) on October 12, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. This order is a combination of Notice of Violation REG-0569-1402-R1 and Notice of Violation REG-0569-1601. The alleged violations occurred during the periods of March 24, 2014 through September 30, 2014 and September 1, 2016 through December 31, 2016. The settlement includes a civil penalty in the amount of $0.4 million and a supplement environmental project in the amount of $0.8 million.

~~Energy Transfer Company Field Services, LLC received~~sent ETP a settlement offer ~~from~~to resolve the ~~NMED on June 6, 2017~~NOV for ~~allegations~~a penalty of $1,151,499. Negotiations for this settlement offer are ongoing.

On September 17, 2018, William D. Warner (“Plaintiff”), a purported ETP unitholder, filed a putative class action asserting violations of ~~New Mexico air regulations related~~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 specifically alleges that the Form S-4 Registration Statement issued in connection with the ETE-ETP Merger omits and/or misrepresents material information. Defendants believe the allegations have no merit and intend to ~~Jal #3 facilities. The alleged violation occurred during~~defend vigorously against them. On October 26, 2018, Plaintiff and Defendants entered into a stipulation staying Defendants’ response deadlines until the ~~period~~designation of ~~January 1, 2017 through September 11, 2017. The NMED is offering to settle~~a lead plaintiff/lead counsel structure in accordance with the ~~violations with a civil penalty of $0.6 million.~~Private Securities Litigation Reform Act.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in ~~our~~the Partnership’s Annual Report on Form 10-K for ~~our previous fiscal~~the year ended December 31, ~~2016 and~~2017 filed with the SEC on February 23, 2018 or from the risk factors described in ~~Exhibit 99.3 to our Current~~“Part II - Item 1A. Risk Factors” in the Partnership’s Quarterly Report on Form ~~8-K~~10-Q for the quarter ended March 31, 2018 filed with the SEC on May ~~8, 2017.~~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.

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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		~~Contribution~~ Agreement and Plan of Merger, dated as of ~~July 30, 2017,~~August 1, 2018, by and among LE GP, LLC, Energy Transfer ~~Interstate Holdings,~~Equity, L.P., Streamline Merger Sub, LLC, ~~ET Rover Pipeline LLC~~Energy Transfer Partners, L.L.C. and ~~BCP Renaissance, L.L.C.~~Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 ofto the Form 8-K ~~File No. 1-31219,~~ filed August ~~2, 2017).~~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 ofto 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 ofto the Current Report on Form 8-K ~~File No. 1-31219,~~ filed April 28, 2017).
3.4		~~Fourth~~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 filed October 19, 2018)
3.5		Fifth Amended and Restated Agreement of Limited Partnership of Energy Transfer ~~Partners,~~Operating, L.P., dated ~~April 28, 2017~~as of October 19, 2018 (incorporated by reference to Exhibit ~~3.4~~3.3 to the Current Report on Form 8-K filed October 19, 2018)
10.1***		Amended and Restated Energy Transfer Partners, L.L.C. Annual Bonus Plan (incorporated by reference to Exhibit 10.3 of Form ~~8-K,~~10-Q, File No. 1-31219, filed ~~April 28, 2017).~~August 9, 2018)
~~4.1~~10.2		~~Fifteenth Supplemental Indenture,~~Amendment No. 1 to Five-Year Credit Agreement, Joinder and Increase and Extension Agreement, dated as of ~~September 21, 2017,~~October 19, 2018, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P., ~~as issuer, Energy Transfer Partners, L.P., as guarantor,~~ and ~~U.S.~~Wells Fargo Bank, National Association, as ~~successor trustee~~administrative agent (incorporated by reference to Exhibit ~~4.2 of~~10.1 to the Current Report on Form 8-K ~~File No. 1-31219,~~ filed ~~September 25, 2017).~~October 19, 2018)
~~4.2~~10.3		~~Form of 4.000% Senior Notes due 2027 (incorporated by reference~~Amendment No. 1 to ~~Exhibit A to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed September 25, 2017).~~
~~4.3~~		~~Sixteenth Supplemental Indenture,~~364-Day Credit Agreement, Joinder and Increase and Extension Agreement, dated as of ~~September 21, 2017,~~October 19, 2018, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners Operations L.P., ~~as issuer, Energy Transfer Partners, L.P., as guarantor,~~ and ~~U.S.~~Wells Fargo Bank, National Association, as ~~successor trustee~~administrative agent (incorporated by reference to Exhibit ~~4.4 of~~10.2 to the Current Report on Form 8-K ~~File No. 1-31219,~~ filed ~~September 25, 2017).~~
~~4.4~~		~~Form of 5.400% Senior Notes due 2047 (incorporated by reference to Exhibit A to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed September 25, 2017).~~
12.1*		~~Computation of Ratio of Earnings to Fixed Charges.~~October 19, 2018)
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.~~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.~~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.~~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.~~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



*		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 ~~PARTNERS,~~OPERATING, L.P.

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

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

Date:	November ~~7, 2017~~8, 2018	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)

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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 of Equity	5

Consolidated Statements of Cash Flows	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	3845

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	5767

ITEM 4. CONTROLS AND PROCEDURES	5969

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	6070

ITEM 1A. RISK FACTORS	6070

ITEM 6. EXHIBITS	6171

SIGNATURE	6272



		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners ⁽¹⁾
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%



	Total Year
2017 (remainder)	$	173
2018	153
2019	128
Each year beyond 2019	33



	September 30, 2017		December 31, 2016
Long-term notes receivable (payable) – related companies:
Sunoco LP	$	85	$	87
Phillips 66	—		(250		)
Net long-term notes receivable (payable) – related companies	$	85	$	(163	)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ ~~(Do not check if a smaller reporting company)~~

Smaller reporting company

Emerging growth company