Energy Transfer LP - Quarter Report: 2018 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2018



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

Commission file number 1-32740

ENERGY TRANSFER LP

(Exact name of registrant as specified in its charter)



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

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Energy Transfer Equity, 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

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



Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨
		Emerging growth company	¨

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

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

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At November 2, 2018, the registrant had 2,617,100,880 Common Units outstanding.

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FORM 10-Q

ENERGY TRANSFER LP AND SUBSIDIARIES

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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	8

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	56

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	77

ITEM 4. CONTROLS AND PROCEDURES	79

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	81

ITEM 1A. RISK FACTORS	81

ITEM 6. EXHIBITS	82

SIGNATURE	84

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Forward-Looking Statements

Certain matters discussed in this report, as well as certain statements by Energy Transfer LP, formerly Energy Transfer Equity, L.P. (“Energy Transfer,” the “Partnership” or “ETE”), in periodic press releases and certain oral statements of Energy Transfer management 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,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected 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 Report on Form 10-K for the year ended December 31, 2017 filed with the Securities and Exchange Commission on February 23, 2018, “Part II — Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 filed on May 10, 2018 and “Part II — Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed on August 9, 2018.

Definitions

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



	/d		per day

	AOCI		accumulated other comprehensive income (loss)

	BBtu		billion British thermal units

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

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

	DOJ		U.S. Department of Justice

	EPA		U.S. Environmental Protection Agency

	ETP		Energy Transfer Operating, L.P. (formerly Energy Transfer Partners, L.P.)

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

	ETP Holdco		ETP Holdco Corporation

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

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

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

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

	Exchange Act		Securities Exchange Act of 1934

	FEP		Fayetteville Express Pipeline LLC

	FERC		Federal Energy Regulatory Commission

	FGT		Florida Gas Transmission Company, LLC

	GAAP		accounting principles generally accepted in the United States of America

	HPC		RIGS Haynesville Partnership Co.

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	IDRs		incentive distribution rights

	Lake Charles LNG		Lake Charles LNG Company, LLC

	LIBOR		London Interbank Offered Rate

	MBbls		thousand barrels

	MEP		Midcontinent Express Pipeline LLC

	MTBE		methyl tertiary butyl ether

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

	NYMEX		New York Mercantile Exchange

	OSHA		Federal Occupational Safety and Health Act

	OTC		over-the-counter

	Panhandle		Panhandle Eastern Pipe Line Company, LP

	PES		Philadelphia Energy Solutions

	Regency		Regency Energy Partners LP

	RIGS		Regency Interstate Gas LP

	Rover		Rover Pipeline LLC

	SEC		Securities and Exchange Commission

	Series A Convertible Preferred Units		ETE Series A convertible preferred units

	Sunoco Logistics		Sunoco Logistics Partners L.P.

	Sunoco LP		Sunoco LP (previously named Susser Petroleum Partners, LP)

	Sunoco LP Series A Preferred Units		Sunoco LP Series A Preferred Units previously held by ETE

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC

	USAC		USA Compression Partners, LP

	USAC Preferred Units		USAC Series A Preferred Units

Adjusted EBITDA is a term used throughout this document. We define 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, gain on deconsolidation 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). Adjusted EBITDA reflects amounts for non-wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

iii

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	September 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	398		$	336
Accounts receivable, net	4,408			4,504
Accounts receivable from related companies	80			53
Inventories	2,066			2,022
Derivative assets	97			24
Income taxes receivable	169			136
Other current assets	303			295
Current assets held for sale	6			3,313
Total current assets	7,527			10,683

Property, plant and equipment	77,819			71,177
Accumulated depreciation and depletion	(12,176		)	(10,089		)
	65,643			61,088

Advances to and investments in unconsolidated affiliates	2,656			2,705
Other non-current assets, net	1,106			886
Intangible assets, net	6,013			6,116
Goodwill	5,242			4,768
Total assets	$	88,187		$	86,246

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)



	September 30, 2018			December 31, 2017
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,986		$	4,685
Accounts payable to related companies	58			31
Derivative liabilities	344			111
Income taxes payable	88			—
Accrued and other current liabilities	3,088			2,582
Current maturities of long-term debt	2,655			413
Current liabilities held for sale	—			75
Total current liabilities	10,219			7,897

Long-term debt, less current maturities	42,117			43,671
Non-current derivative liabilities	58			145
Deferred income taxes	3,008			3,315
Other non-current liabilities	1,253			1,217

Commitments and contingencies
Redeemable noncontrolling interests	499			21

Equity:
Limited Partners:
Series A Convertible Preferred Units	—			450
Common Unitholders	(1,099		)	(1,643		)
General Partner	(4		)	(3		)
Total partners’ deficit	(1,103		)	(1,196		)
Noncontrolling interest	32,136			31,176
Total equity	31,033			29,980
Total liabilities and equity	$	88,187		$	86,246

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017*			2018			2017*
REVENUES:
Natural gas sales	$	1,026		$	1,098		$	3,112		$	3,132
NGL sales	2,695			1,749			6,866			4,782
Crude sales	3,841			2,381			11,336			7,268
Gathering, transportation and other fees	1,781			1,068			4,878			3,244
Refined product sales	4,955			3,080			13,583			8,998
Other	216			608			739			1,648
Total revenues	14,514			9,984			40,514			29,072
COSTS AND EXPENSES:
Cost of products sold	11,093			7,341			31,681			22,018
Operating expenses	784			918			2,280			2,167
Depreciation, depletion and amortization	750			642			2,109			1,877
Selling, general and administrative	184			142			515			480
Impairment losses	—			10			—			99
Total costs and expenses	12,811			9,053			36,585			26,641
OPERATING INCOME	1,703			931			3,929			2,431
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(535		)	(490		)	(1,511		)	(1,440		)
Equity in earnings of unconsolidated affiliates	87			92			258			228
Gains on disposal of assets	18			5			14			—
Losses on extinguishments of debt	—			—			(106		)	(25		)
Gains (losses) on interest rate derivatives	45			(8		)	117			(28		)
Other, net	23			54			83			133
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)	1,341			584			2,784			1,299
Income tax expense (benefit) from continuing operations	(52		)	(157		)	6			(86		)
INCOME FROM CONTINUING OPERATIONS	1,393			741			2,778			1,385
Income (loss) from discontinued operations, net of income taxes	(2		)	17			(265		)	(187		)
NET INCOME	1,391			758			2,513			1,198
Less: Net income attributable to noncontrolling interest	1,008			506			1,412			495
Less: Net income attributable to redeemable noncontrolling interests	12			—			24			—
NET INCOME ATTRIBUTABLE TO PARTNERS	371			252			1,077			703
Convertible Unitholders' interest in income	—			11			33			25
General Partner’s interest in net income	1			1			3			2
Limited Partners’ interest in net income	$	370		$	240		$	1,041		$	676
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.32		$	0.22		$	0.94		$	0.63
Diluted	$	0.32		$	0.22		$	0.94		$	0.62
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.32		$	0.22		$	0.93		$	0.62
Diluted	$	0.32		$	0.22		$	0.93		$	0.61

* As adjusted. See Note 1.

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017*		2018			2017*
Net income	$	1,391	$	758	$	2,513		$	1,198
Other comprehensive income, net of tax:
Change in value of available-for-sale securities	2		2		—			5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	—		5		(2		)	2
Change in other comprehensive income from unconsolidated affiliates	2		—		9			(1		)
	4		7		7			6
Comprehensive income	1,395		765		2,520			1,204
Less: Comprehensive income attributable to noncontrolling interest	1,024		513		1,443			501
Comprehensive income attributable to partners	$	371	$	252	$	1,077		$	703

* As adjusted. See Note 1.

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

(Dollars in millions)

(unaudited)



	Series A Convertible Preferred Units			Common Unitholders			General Partner			Noncontrolling Interest			Total
Balance, December 31, 2017	$	450		$	(1,643	)	$	(3	)	$	31,176		$	29,980
Distributions to partners	—			(883		)	(3		)	—			(886		)
Distributions to noncontrolling interest	—			—			—			(2,742		)	(2,742		)
Distributions reinvested	115			(115		)	—			—			—
Subsidiary units repurchased	(7		)	(119		)	—			102			(24		)
Subsidiary units issued	—			1			—			937			938
Capital contributions received from noncontrolling interests	—			—			—			438			438
Other comprehensive income, net of tax	—			—			—			7			7
Cumulative effect adjustment due to change in accounting principle (see Note 1)	—			—			—			(54		)	(54		)
Acquisition of USAC	—			—			—			832			832
Series A Convertible Preferred Units conversion	(589		)	589			—			—			—
Other, net	(2		)	30			(1		)	28			55
Net income, excluding amounts attributable to redeemable noncontrolling interests	33			1,041			3			1,412			2,489
Balance, September 30, 2018	$	—		$	(1,099	)	$	(4	)	$	32,136		$	31,033

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Nine Months Ended September 30,
	2018			2017*
OPERATING ACTIVITIES
Net income	$	2,513		$	1,198
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	265			187
Depreciation, depletion and amortization	2,109			1,877
Deferred income taxes	1			(64		)
Non-cash compensation expense	82			76
Impairment losses	—			99
Loss on extinguishment of debt	106			25
Equity in earnings of unconsolidated affiliates	(258		)	(228		)
Distributions from unconsolidated affiliates	220			211
Inventory valuation adjustments	(50		)	(8		)
Distributions on unvested awards	(36		)	(24		)
Other non-cash	(80		)	(131		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation	423			192
Net cash provided by operating activities	5,295			3,410
INVESTING ACTIVITIES
Cash received in USAC acquisition (net of cash paid)	461			—
Cash proceeds from sale of Bakken Pipeline interest	—			2,000
Cash paid for other acquisitions (net of cash received)	(233		)	(573		)
Capital expenditures (excluding allowance for equity funds used during construction)	(5,175		)	(6,126		)
Contributions in aid of construction costs	95			25
Contributions to unconsolidated affiliates	(13		)	(230		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	62			115
Proceeds from the sale of other assets	40			37
Other	—			(33		)
Net cash used in by investing activities	(4,763		)	(4,785		)
FINANCING ACTIVITIES
Proceeds from borrowings	22,126			23,988
Repayments of long-term debt	(23,323		)	(22,536		)
Cash paid on affiliate notes	—			(255		)
Subsidiary units repurchased	(24		)	—
Units issued for cash	—			568
Subsidiary units and warrants issued for cash	1,403			1,635
Distributions to partners	(886		)	(752		)
Distributions on USAC Preferred Units	(12		)	—
Debt issuance costs	(188		)	(85		)
Distributions to noncontrolling interests	(2,742		)	(2,156		)
Capital contributions from noncontrolling interest	438			919

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

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Redemption of ETP Convertible Preferred Units	—			(53		)
Other, net	—			30
Net cash (used in) provided by financing activities	(3,208		)	1,303
DISCONTINUED OPERATIONS
Operating activities	(480		)	139
Investing activities	3,207			(57		)
Changes in cash included in current assets held for sale	11			(2		)
Net increase in cash and cash equivalents of discontinued operations	2,738			80
Increase in cash and cash equivalents	62			8
Cash and cash equivalents, beginning of period	336			467
Cash and cash equivalents, end of period	$	398		$	475

* As adjusted. See Note 1.

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)


1.	ORGANIZATION AND BASIS OF PRESENTATION

Organization

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer LP (formerly Energy Transfer Equity, L.P., as discussed below) and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

The consolidated financial statements of ETE presented herein include the results of operations of:


•	the Parent Company;


•	our controlled subsidiaries, ETP, Sunoco LP and, beginning April 2018, USAC;


•	consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that owned general partner interests and IDRs in ETP and Sunoco LP, and the general partner interests in USAC; and


•	our wholly-owned subsidiary, Lake Charles LNG.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

On September 30, 2018, our interests in ETP, Sunoco LP and USAC consisted of 100% of the respective general partner interests and IDRs in ETP and Sunoco LP, as well as approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units, and approximately 20.5 million USAC common units. Additionally, ETE owned 100 ETP Class I Units, which were not entitled to any distributions.

ETE-ETP Merger and Name Change

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.

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Business Operations

The Parent Company’s principal sources of cash flow have been derived from its direct and indirect investments in ETP, Sunoco LP, USAC and Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 16 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our financial statements reflect the following reportable business segments:


•	Investment in ETP, including the consolidated operations of ETP;


•	Investment in Sunoco LP, including the consolidated operations of Sunoco LP;


•	Investment in USAC, including the consolidated operations of USAC;


•	Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and


•	Corporate and Other, including the following:


•	activities of the Parent Company; and


•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017, filed with the SEC on 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 other prior period amounts were reclassified to conform to the 2018 presentation. Additionally, there are reclassifications of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.

Change in Accounting Policy

Inventory Accounting Change

During the fourth quarter of 2017, we elected to change our 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 product and NGL associated with the legacy Sunoco Logistics business. Our management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity.

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As a result of this change in accounting policy, the consolidated statement of operations and comprehensive income in prior periods have been retrospectively adjusted, as follows:



	Three Months Ended							Nine Months Ended
	September 30, 2017							September 30, 2017
	As Originally Reported*		Effect of Change			As Adjusted		As Originally Reported*		Effect of Change			As Adjusted
Cost of products sold	$	7,295	$	46		$	7,341	$	22,005	$	13		$	22,018
Operating income	977		(46		)	931		2,444		(13		)	2,431
Income before income tax expense	630		(46		)	584		1,312		(13		)	1,299
Net income	804		(46		)	758		1,211		(13		)	1,198
Net loss attributable to noncontrolling interest	552		(46		)	506		508		(13		)	495
Comprehensive income	811		(46		)	765		1,217		(13		)	1,204

* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2.

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	$	1,211		$	(13	)	$	1,198
Inventory Valuation Adjustments	(38		)	30			(8		)
Net change in operating assets and liabilities (change in inventories)	209			(17		)	192

* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2.

Revenue Recognition Standard

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

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

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

For contracts in scope of the new revenue standard as of January 1, 2018, the Partnership recognized a cumulative effect adjustment to retained earnings to account for the differences in timing of revenue recognition. The comparative information

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has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods.

The adjustments to the opening balance sheet primarily relate to a change in timing of revenue recognition for variable consideration at Sunoco LP, such as incentives paid to customers, as well as a change in timing of revenue recognition for franchise fee revenue. Historically, an asset was recognized related to the contract incentives which was amortized over the life of the agreement. Under the new standard, the timing of the recognition of incentives changed due to application of the expected value method to estimate variable consideration. Additionally, under the new standard the change in timing of franchise fee revenue is due to the treatment of revenue recognition from the symbolic license over the term of the agreement.

The cumulative effect of the changes made to the Partnership’s consolidated balance sheet for the adoption of ASU 2014-09 was as follows:



	Balance at December 31, 2017		Adjustments due to ASC 606			Balance at January 1, 2018
Assets:
Other current assets	$	295	$	8		$	303
Property and Equipment, net	61,088		—			61,088
Other non-current assets, net	886		39			925
Intangible assets, net	6,116		(100		)	6,016

Liabilities and Equity:
Other non-current liabilities	$	1,217	$	1		$	1,218
Noncontrolling interest	31,176		(54		)	31,122

The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales, and operating expenses. Additionally, changes in timing of revenue recognition have required the creation of contract asset or contract liability balances, as well as certain balance sheet reclassifications. In accordance with the requirements of ASC Topic 606, the disclosure below shows the impact of adopting the new standard on the consolidated statement of operations and the consolidated balance sheet.



	Three Months Ended							Nine Months Ended
	September 30, 2018							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	1,781		1,985		(204		)	4,878		5,415		(537		)
Refined product sales	4,955		4,968		(13		)	13,583		13,619		(36		)
Other	216		216		—			739		739		—

Costs and expenses:
Cost of products sold	$	11,093	$	11,298	$	(205	)	$	31,681	$	32,221	$	(540	)
Operating expenses	784		773		11			2,280		2,248		32
Depreciation and amortization	750		758		(8		)	2,109		2,130		(21		)

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	September 30, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Assets:
Other current assets	$	303	$	292	$	11
Property and Equipment, net	65,643		65,643		—
Intangible assets, net	6,013		6,135		(122		)
Other non-current assets, net	1,106		1,055		51

Liabilities and Equity:
Other non-current liabilities	$	1,253	$	1,252	$	1
Noncontrolling interest	32,136		32,197		(61		)

Additional disclosures related to revenue are included in Note 12.

Use of Estimates

The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

Recent 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 information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance in Topic 840. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this 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 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 lease obligations.

ASU 2017-12

In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

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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 OTHER INVESTING TRANSACTIONS

ETE-ETP Merger and Related Contribution of Assets to ETP

Immediately prior to the closing of the ETE-ETP Merger discussed in Note 1, 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;


•	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 to ETP in exchange for 37,557,815 ETP common units.

ETE will continue to consolidate each of these entities in its consolidated financial statements subsequent to the ETE-ETP Merger, and these transactions will not impact the carrying values of the related assets and liabilities.

USAC Transactions

On April 2, 2018, ETE acquired a controlling interest in USAC, a publicly traded partnership that provides compression services in the United States. Specifically ETE acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC (“USAC GP”), the general partner of USAC, and (ii) 12,466,912 USAC common units representing limited partner interests in USAC for cash consideration equal to $250 million (the “USAC Transaction”). Concurrently, USAC cancelled its incentive distribution rights and converted its economic general partner interest into a non-economic general partner interest in exchange for the issuance of 8,000,000 USAC common units to USAC GP.

Concurrent with these transactions, 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 USAC common units, (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, ETE’s consolidated financial statements reflected USAC as a consolidated subsidiary.

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Summary of Assets Acquired and Liabilities Assumed

We accounted for the USAC Transaction using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

The total purchase price was allocated as follows:



	At April 2, 2018
Total current assets	$	786
Property, plant and equipment	1,332
Other non-current assets	15
Goodwill⁽¹⁾	366
Intangible assets	222
	2,721

Total current liabilities	110
Long-term debt, less current maturities	1,527
Other non-current liabilities	2
	1,639

Noncontrolling interest	832

Total consideration	250
Cash received⁽²⁾	711
Total consideration, net of cash received⁽²⁾	$	(461	)


⁽¹⁾	None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations.


⁽²⁾	Cash received represents cash and cash equivalents held by USAC as of the acquisition date.

The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

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 the Partnership’s consolidated financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in the Partnership’s consolidated financial statements.

Sunoco LP Retail Store and Real Estate Sales

On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-11 Transaction”). As a result of the 7-11 Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties. Also, the related accounts receivable from such sales are no longer eliminated from the Partnership’s consolidated balance sheets and are reported as accounts receivable.

In connection with the 7-11 Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated as of January 23, 2018 (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists of a 15-year take-or-pay fuel supply arrangement under which Sunoco LP has agreed to supply approximately 2.0 billion gallons of fuel annually plus additional aggregate growth volumes of up to 500 million gallons to be added incrementally over the first four years. For the period from January 1, 2018 through January 22, 2018 and the three and nine months ended September 30, 2017, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, $926 million and $2.4 billion, respectively, which were eliminated in consolidation. Sunoco LP payments on trade receivables of

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$1 billion and $2.6 billion from 7-Eleven in the three and nine months ended September 30, 2018 subsequent to the closing of the sale.

On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties are being sold through a sealed-bid. Of the 97 properties, 50 have been sold, one is under contract to be sold, and five continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which are operated by a commission agent.

The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of Sunoco LP’s retail divestment as discontinued operations.

The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:



	September 30, 2018		December 31, 2017
Carrying amount of assets classified as held for sale:
Cash and cash equivalents	$	—	$	21
Inventories	—		149
Other current assets	—		16
Property, plant and equipment, net	6		1,851
Goodwill	—		796
Intangible assets, net	—		477
Other non-current assets, net	—		3
Total assets classified as held for sale in the Consolidated Balance Sheet	$	6	$	3,313

Carrying amount of liabilities classified as held for sale:
Other current and non-current liabilities	$	—	$	75
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	—	$	75

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The results of operations associated with discontinued operations are presented in the following table:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
REVENUES	$	—		$	1,802		$	349		$	5,145

COSTS AND EXPENSES
Cost of products sold	—			1,482			305			4,274
Operating expenses	—			182			61			566
Depreciation, depletion and amortization	—			(5		)	—			31
Impairment losses	—			34			—			265
Selling, general and administrative	—			57			7			126
Total costs and expenses	—			1,750			373			5,262
OPERATING LOSS	—			52			(24		)	(117		)
Interest expense, net	—			13			2			21
Loss on extinguishment of debt and other	—			—			20			—
Other, net	—			(8		)	61			—
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	—			47			(107		)	(138		)
Income tax expense	2			30			158			49
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(2	)	$	17		$	(265	)	$	(187	)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE ATTRIBUTABLE TO ETE	$	—		$	1		$	(10	)	$	(6	)

3. CASH AND CASH EQUIVALENTS

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

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.

Non-cash investing and financing activities were as follows:



	Nine Months Ended September 30,
	2018			2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,059		$	1,237
Losses from subsidiary common unit transactions	(125		)	(57		)
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—		$	988
Conversion of Series A Convertible Preferred Units to common units	589			—

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4. INVENTORIES

Inventories consisted of the following:



	September 30, 2018		December 31, 2017
Natural gas, NGLs, and refined products	$	1,072	$	1,120
Crude oil	643		551
Spare parts and other	351		351
Total inventories	$	2,066	$	2,022

We utilize commodity derivatives to manage price volatility associated with its natural gas inventories. 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.

USAC’s inventory consists of serialized and non-serialized parts used primarily in the repair of compression units. All inventory is stated at the lower of cost or net realizable value. The cost of serialized parts inventory is determined using the specific identification cost method, while the cost of non-serialized parts inventory is determined using the weighted average cost method. Purchases of these assets are considered operating activities on the Consolidated Statements of Cash Flows.

5. FAIR VALUE MEASURES

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2018 were $45.54 billion and $44.77 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.62 billion and $44.08 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.

We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the nine months ended September 30, 2018, no transfers were made between any levels within the fair value hierarchy.

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



				Fair Value Measurements at September 30, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	48		$	48		$	—
Swing Swaps IFERC	1			—			1
Fixed Swaps/Futures	25			25			—
Forward Physical Contracts	12			—			12
Power:
Forwards	36			—			36
Options — Puts	1			1			—
NGLs — Forwards/Swaps	476			476			—
Refined Products — Futures	4			4			—
Total commodity derivatives	603			554			49
Other non-current assets	28			18			10
Total assets	$	631		$	572		$	59
Liabilities:
Interest rate derivatives	$	(97	)	$	—		$	(97	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(89		)	(89		)	—
Swing Swaps IFERC	(1		)	—			(1		)
Fixed Swaps/Futures	(26		)	(26		)	—
Forward Physical Contracts	(7		)	—			(7		)
Power:
Forwards	(30		)	—			(30		)
Futures	(1		)	(1		)	—
NGLs — Forwards/Swaps	(522		)	(522		)	—
Refined Products — Futures	(10		)	(10		)	—
Crude — Forwards/Swaps	(191		)	(191		)	—
Total commodity derivatives	(877		)	(839		)	(38		)
Total liabilities	$	(974	)	$	(839	)	$	(135	)

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				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			—
Refined Products — Futures	1			1			—
Crude:
Forwards/Swaps	2			2			—
Futures	2			2			—
Total commodity derivatives	321			277			44
Other non-current assets	21			14			7
Total assets	$	342		$	291		$	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	(28		)	(28		)	—
Crude:
Forwards/Swaps	(6		)	(6		)	—
Futures	(1		)	(1		)	—
Total commodity derivatives	(341		)	(303		)	(38		)
Total liabilities	$	(560	)	$	(303	)	$	(257	)

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6. NET INCOME PER LIMITED PARTNER UNIT

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017*		2018			2017*
Income from continuing operations	$	1,393	$	741	$	2,778		$	1,385
Less: Net income attributable to redeemable noncontrolling interests	12		—		24			—
Less: Income from continuing operations attributable to noncontrolling interest	1,010		491		1,667			676
Income from continuing operations, net of noncontrolling interest	371		250		1,087			709
Less: Convertible Unitholders’ interest in income	—		11		33			25
Less: General Partner’s interest in income	1		1		3			2
Income from continuing operations available to Limited Partners	$	370	$	238	$	1,051		$	682
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,158.2		1,079.1		1,117.7			1,077.9
Basic income from continuing operations per Limited Partner unit	$	0.32	$	0.22	$	0.94		$	0.63
Basic income (loss) from discontinued operations per Limited Partner unit	$	0.00	$	0.00	$	(0.01	)	$	(0.01	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	370	$	238	$	1,051		$	682
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	—		11		33			25
Diluted income from continuing operations available to Limited Partners	$	370	$	249	$	1,084		$	707
Weighted average limited partner units	1,158.2		1,079.1		1,117.7			1,077.9
Dilutive effect of unconverted unit awards and Convertible Units	—		69.2		40.5			69.5
Diluted weighted average limited partner units	1,158.2		1,148.3		1,158.2			1,147.4
Diluted income from continuing operations per Limited Partner unit	$	0.32	$	0.22	$	0.94		$	0.62
Diluted income (loss) from discontinued operations per Limited Partner unit	$	0.00	$	0.00	$	(0.01	)	$	(0.01	)

* As adjusted. See Note 1.

7. DEBT OBLIGATIONS

Parent Company Indebtedness

The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.

ETE Revolving Credit Facility

As of September 30, 2018, borrowings of $898 million were outstanding under the Parent Company revolving credit facility. In connection with the closing of the ETE-ETP Merger, on October 19, 2018, the Partnership repaid in full all outstanding borrowings under the facility and the facility was terminated.

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Subsidiary Indebtedness

ETP Senior Notes Offering and Redemption

In June 2018, ETP issued the following senior notes:

•$500 million aggregate principal amount of 4.20% senior notes due 2023;

•$1.00 billion aggregate principal amount of 4.95% senior notes due 2028;

•$500 million aggregate principal amount of 5.80% senior notes due 2038; and

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

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

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 ETP’s subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of ETP’s 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;

•Panhandle’s $400 million aggregate principal amount of 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.

ETP Five-Year Credit Facility

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

As of September 30, 2018, the ETP Five-Year Credit Facility had $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 September 30, 2018 was 3.00%.

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.

Bakken Credit Facility

In August 2016, ETP and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50 billion credit facility matures in August 2019 (the “Bakken Credit Facility”). As of September 30, 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 3.85%.

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Sunoco LP Senior Notes and Term Loan


•	redeem in full its existing senior notes, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023;


•	repay in full and terminate its term loan;


•	pay all closing costs in connection with the 7-Eleven transaction;


•	redeem the outstanding Sunoco LP Series A Preferred Units; and


•	repurchase 17,286,859 Sunoco LP common units owned by ETP.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement. In July 2018, Sunoco LP amended its revolving credit agreement, including extending the expiration to July 2023 (which may be extended in accordance with the terms of the credit agreement). Borrowings under the amended revolving credit agreement were used to pay off Sunoco LP’s existing revolving credit facility which was entered into in September 2014.

As of September 30, 2018, the Sunoco LP credit facility had $493 million outstanding borrowings and $8 million in standby letters of credit. The unused availability on the revolver at September 30, 2018 was $999 million.

USAC Credit Facility

USAC currently has a $1.6 billion revolving credit facility, which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity.

As of September 30, 2018, USAC had $1.0 billion of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of September 30, 2018, USAC had $578 million of availability under its credit facility.

USAC Senior Notes

USAC has outstanding $725 million aggregate principal amount of senior notes that mature on April 1, 2026. The notes accrue interest from March 23, 2018 at the rate of 6.875% per year. Interest on the notes will be payable semi-annually in arrears on each April 1 and October 1, commencing on October 1, 2018.

Compliance with Our Covenants

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

8. REDEEMABLE NONCONTROLLING INTERESTS

Certain redeemable noncontrolling interest in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of September 30, 2018 include (i) a balance of $477 million related to the USAC Preferred Units described below and (ii) a balance of $22 million related to noncontrolling interest holders in one of ETP’s consolidated subsidiaries that have the option to sell their interests to ETP.

USAC Series A Preferred Units

On April 2, 2018, USAC issued 500,000 USAC Preferred Units at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million in a private placement.

The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units will be convertible into USAC common units at the election of the holders beginning in 2021. To the extent the holders of the USAC Preferred Units have not elected to convert

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their preferred units by the fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the USAC Preferred Units for cash. In addition, at any time on or after the tenth anniversary of the issue date, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.

9. EQUITY

ETE

The changes in ETE common units and ETE Series A Convertible Preferred Units during the nine months ended September 30, 2018 were as follows:



	Number of ETE Series A Convertible Preferred Units		Number of Common Units
Outstanding at December 31, 2017	329.3		1,079.1
Conversion of ETE Series A Convertible Preferred Units to common units	(329.3	)	79.1
Outstanding at September 30, 2018	—		1,158.2

In October 2018, ETE issued 1.46 billion ETE Common Units in connection with the ETE-ETP Merger.

ETE Equity Distribution Program

In March 2017, the Partnership entered into an equity distribution agreement relating to at-the-market offerings of its common units with an aggregate offering price up to $1 billion. As of September 30, 2018, there have been no sales of common units under the equity distribution agreement.

ETE Series A Convertible Preferred Units

In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million common units in accordance with the terms of our partnership agreement.

ETE Class A Units

In connection with the ETE-ETP Merger, the Partnership issued 647,745,099 Class A units (“ETE Class A Units”) representing limited partner interests in the Partnership to LE GP, LLC (“LE GP”), the general partner of ETE. The number of ETE Class A Units issued allows LE GP and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Merger. The ETE Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ETE’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ETE Class A Units additional ETE Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The ETE Class A Units are not entitled to distributions and otherwise have no economic attributes.

Repurchase Program

During the nine months ended September 30, 2018, ETE did not repurchase any ETE common units under its current buyback program. As of September 30, 2018, $936 million remained available to repurchase under the current program.

Subsidiary Equity Transactions

The Parent Company accounts for the difference between the carrying amount of its investment in ETP, Sunoco LP, and USAC and the underlying book value arising from the issuance or redemption of units by ETP, Sunoco LP, and USAC (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the nine months ended September 30, 2018, we recognized a decrease in partners’ capital of $125 million.

ETP Equity Distribution Program

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

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ETP Distribution Reinvestment Program

In July 2017, ETP initiated a new distribution reinvestment plan. During the nine months ended September 30, 2018, distributions of $57 million were reinvested under ETP’s distribution reinvestment plan. In connection with the ETE-ETP Merger, the distribution reinvestment program was terminated in October 2018.

ETP Preferred Units

ETP issued 950,000 ETP Series A Preferred Units and 550,000 ETP Series B Preferred Units in November 2017 and has issued additional preferred units in 2018, as discussed below. Subsequent to the ETE-ETP Merger, all of ETP’s Series A, Series B, Series C and Series D Preferred Units remain outstanding.

ETP Series C Preferred Units Issuance

In April 2018, ETP issued 18 million of its 7.375% ETP Series C Preferred Units at a price of $25 per unit, resulting in total gross proceeds of $450 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.

Distributions on the ETP 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 ETP 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 ETP Series C Preferred Units are redeemable at ETP’s option on or after May 15, 2023 at a redemption price of $25 per ETP Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

ETP Series D Preferred Units Issuance

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

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

Sunoco LP Common Unit Transactions

On February 7, 2018, subsequent to the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.

Sunoco LP Series A Preferred Units

On January 25, 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount includes the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.

USAC Warrant Private Placement

On April 2, 2018, USAC issued two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in common units on a net basis.

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USAC Class B Units

The USAC Class B Units, all of which are owned by ETP, 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 the USAC Transaction on 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.

USAC Distribution Reinvestment Program

During the six months ended September 30, 2018, distributions of $0.4 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 24,261 USAC common units.

Parent Company Cash Distributions

Distributions declared and/or paid subsequent to December 31, 2017 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017⁽¹⁾	February 8, 2018	February 20, 2018	$	0.3050
March 31, 2018⁽¹⁾	May 7, 2018	May 21, 2018	0.3050
June 30, 2018	August 6, 2018	August 20, 2018	0.3050
September 30, 2018	November 8, 2018	November 19, 2018	0.3050

⁽¹⁾

Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forgo their cash distributions on all or a portion of their common units, and in lieu of receiving cash distributions on these common units for each such quarter, such unitholder received Series A Convertible Preferred Units, and (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Series A Convertible Preferred Unit. The quarter ended March 31, 2018 was the final quarter of participation in the plan.

Distributions declared and/or paid with respect to our Series A Convertible Preferred Units subsequent to December 31, 2017 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017	February 8, 2018	February 20, 2018	$	0.1100
March 31, 2018	May 7, 2018	May 21, 2018	0.1100

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ETP Cash Distributions

Distributions declared and/or paid by ETP subsequent to December 31, 2017 but prior to the closing of the ETE-ETP Merger as discussed in Note 1 were as follows:



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

Distributions on ETP’s preferred units declared and paid by ETP subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
ETP 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
ETP 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
ETP 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
ETP Series D Preferred Units
September 30, 2018	November 1, 2018	November 15, 2018	0.5931

Sunoco LP Cash Distributions

The following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2017:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017	February 6, 2018	February 14, 2018	$	0.8255
March 31, 2018	May 7, 2018	May 15, 2018	0.8255
June 30, 2018	August 7, 2018	August 15, 2018	0.8255
September 30, 2018	November 6, 2018	November 14, 2018	0.8255

USAC Cash Distributions

Subsequent to the USAC Transactions described in Note 2, ETE and its wholly-owned subsidiaries own an aggregate 20,466,912 USAC common units, and ETP owns 19,191,351 USAC common units and 6,397,965 USAC Class B units. As of September 30, 2018, USAC had 89,966,676 common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights.

The following are distributions declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018:



Quarter Ended	Record Date	Payment Date	Rate
March 31, 2018	May 1, 2018	May 11, 2018	$	0.5250
June 30, 2018	July 30, 2018	August 10, 2018	0.5250
September 30, 2018	October 29, 2018	November 09, 2018	0.5250

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Accumulated Other Comprehensive Income

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



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

⁽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 ETP’s accumulated other comprehensive income related to available-for-sale securities to ETP’s common unitholders. The amount is reflected as a change in noncontrolling interest in the Partnership’s consolidated financial statements.


10.	INCOME TAXES

The Partnership’s effective tax rate differs from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. For the three and nine months ended September 30, 2018, the Partnership’s income tax benefit also reflected $113 million and $164 million, respectively, of deferred benefit adjustments as the 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 Internal 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 CFC ruled against Sunoco, Inc., and the 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. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

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

ETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their 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 with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. 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,
	2018			2017			2018			2017
Rental expense ⁽¹⁾	$	43		$	49		$	117		$	130
Less: Sublease rental income	(11		)	(7		)	(28		)	(19		)
Rental expense, net	$	32		$	42		$	89		$	111


⁽¹⁾	Includes contingent rentals totaling $1 million and $3 million for three months ended September 30, 2018 and 2017, respectively and $3 million and $13 million for the nine months ended September 30, 2018 and 2017, respectively.

Litigation and Contingencies

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

Dakota Access Pipeline

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

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

On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court concluded that the USACE had not violated trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. On May 3, 2018, the District Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they will conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they will need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. The USACE

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indicated that a document detailing its remand analysis would be filed after a “confidentiality review.” Following the submission by USACE of its detailed remand analysis, it is expected that the Court will make a determination regarding the three discrete issues covered by the remand order.

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

In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline.

On 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 from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access pipeline and the USACE opposed both motions. On April 16, 2018, the Court denied both motions.

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

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 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), LLC) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of September 30, 2018, Sunoco, Inc. is a defendant in six cases, including one case each initiated by the States of Maryland, Vermont and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P.

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

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It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-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 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 (“Defendants”).

The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. Trial is currently set for September 23-27, 2019.

The Regency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.

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 $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 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. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETP’s petition for review remains under consideration by the Texas Supreme Court.

ETE-ETP Merger Litigation

On September 17, 2018, William D. Warner (“Plaintiff”), a purported ETP unitholder, filed a putative class action asserting violations of various provisions of the Securities Exchange Act of 1934 and various rules promulgated thereunder in connection with the ETE-ETP Merger against ETP, Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff 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 Private Securities Litigation Reform Act.

Litigation Filed By or Against Williams

On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the issuance of the Partnership’s Series A Convertible Preferred Units (the “Issuance”) and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

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On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the ETE-Williams merger agreement (the “Merger Agreement”) by (a) blocking ETE’s attempts to complete a public offering of the Series A Convertible Preferred Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.

On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”) (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.

ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee, and Defendants filed amended counterclaims and affirmative defenses. In response, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses.

On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June trial, and as a result, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying Williams’ motion to dismiss in part. Trial is set for May 20, 2019.

Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

Unitholder Litigation Relating to the Issuance

On April 12, 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, later joined the Issuance Litigation.

The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

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On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.

The matter was tried in front of Vice Chancellor Glasscock on February 19-21, 2018. Post-trial arguments were heard on April 16, 2018. In a post-trial opinion dated May 17, 2018, the Court found that one provision of the Issuance breached ETE’s partnership agreement but that this breach caused no damages. The Court denied Plaintiffs’ requests for injunctive relief and declined to award damages other than nominal damages. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses from the Issuance Defendants, which the Issuance Defendants have opposed.

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

Bayou Bridge

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

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

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 “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 11, 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.

Rover

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

Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, 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

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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 to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2018 and December 31, 2017, accruals of approximately $62 million and $53 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

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

On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against Sunoco Pipeline L.P. (“SPLP”) before the Pennsylvania Public Utility Commission (“PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in the Township.

Following a hearing on May 7, 2018 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the Pennsylvania Department of Environmental Protection (“PADEP”) has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018 the PUC entered an Order lifting the stay of construction on ME2 and ME2x in the Township with respect to four of the eight areas within the

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Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of permit modifications for two of the four remaining construction sites, the PUC lifted the construction stay on those two sites as well.

Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue the action. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition. On September 27, 2018, the Commonwealth Court issued an Order that certified for appeal the issue of Senator Dinniman’s standing. The Order stays all proceedings in the 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 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.

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

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

Environmental Matters

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

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 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 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 2014; and (c) an

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estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January 2015. In July 2017, we had a 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. Since then, the parties have reached an agreement in principal to resolve all penalties with DOJ and LDEQ along with 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 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that SPLP had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018.

Environmental Remediation

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


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


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


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

•

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2018, Sunoco, Inc. had been named as a PRP at approximately 41 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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



	September 30, 2018		December 31, 2017
Current	$	43	$	35
Non-current	347		337
Total environmental liabilities	$	390	$	372

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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, the Partnership recorded $17 million and $8 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2018 and 2017, the Partnership recorded $32 million and $26 million, respectively, of expenditures related to environmental cleanup programs.

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

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health 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.

12. 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 major types of revenue within our reportable segment, are as follows:

•Investment in ETP


•	intrastate transportation and storage


•	interstate transportation and storage


•	midstream


•	NGL and refined products transportation and services


•	crude oil transportation and services


•	all other

•Investment in Sunoco LP


•	fuel distribution and marketing


•	all other

•Investment in USAC


•	contract operations

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•	retail parts and services


•	station installations

•Investment in Lake Charles LNG


•	terminal services

Note 15 depicts the disaggregation of revenue amounts by type for each of our reportable segments, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

ETP’s intrastate transportation and storage revenue

ETP’s intrastate transportation and storage 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.

ETP’s interstate transportation and storage revenue

ETP’s interstate transportation and storage 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 contracts can be firm or interruptible. 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 withdrawn 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.

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ETP’s midstream revenue

ETP’s midstream 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 operations enter 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, processes the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent amount 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 retains 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 NGL’s 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 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 statement of operations; therefore, identification of separate performance obligations would not impact the timing or geography of revenue recognition.

Certain contracts of our midstream operations 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, 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.

ETP’s NGL and refined products transportation and services revenue

ETP’s NGL and refined products 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

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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 our NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.

ETP’s crude oil transportation and services revenue

ETP’s crude oil operations 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.

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.

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

ETP’s all other revenue

ETP’s other operations primarily include 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 related to these operations are recorded under the new standard.

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Sunoco LP’s fuel distribution and marketing revenue

Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to Dealers, sales to Distributors, Unbranded Wholesale Revenue, Commission Agent Revenue, Rental Income and Other Income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method.

Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized.

Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer.

Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease.

Sunoco LP’s all other revenue

Sunoco LP’s all other operations earn revenue from the following channels: Motor Fuel Sales, Rental Income and Other Income. Motor Fuel Sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided).

USAC’s contract operations revenue

USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.

Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.

USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determine standalone service fees based on the service fees charged to customers or using expected cost plus margin.

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The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date.

There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration.

USAC’s retail parts and services revenue

USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration.

USAC’s station installations revenue

USAC’s revenue from station installations is earned on stations USAC builds on behalf of, and sell to, its customers and such revenue is recognized over time as services are provided. A station typically consists of compressor equipment combined with other equipment ancillary to compression, such as slug catchers, pipe racks, tanks, dehydration units, valves, and control rooms, which together assist in the treating, processing, pressurization and transportation of natural gas. USAC’s performance enhances an asset that the customer controls and does not create an asset with alternative use to USAC. Revenue is recognized over time based on the progress-toward-completion method and progress is measured using the efforts-expended input method. In applying the efforts-expended input method, USAC uses the percentage of total completed workflows to date relative to estimated total workflows to determine the amount of revenue and profit to recognize for each contract. The amount of consideration USAC receives and revenue it recognizes varies in accordance with each contractual agreement negotiated with its customers.

The progress-toward-completion method of revenue recognition requires USAC to make estimates of contract revenues and costs to complete its projects. In making such estimates, management judgments are required to evaluate significant assumptions including the cost of materials and labor, expected labor productivity, the impact of potential variances in schedule completion, the amount of net contract revenues and the impact of any penalties, claims, change orders, or performance incentives.

USAC’s payment terms vary in accordance with each contractual agreement negotiated with its customers. The term between invoicing and when payment is due is not significant. USAC retains the right to payment for performance completed to date at any point during the contract term. There are no material obligations for returns, refunds, or warranties.

Lake Charles LNG revenue

Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed.

The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal.

The performance obligation with respect to firm contracts is a promise to provide a single type of service (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

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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.

Contract Balances with Customers

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

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

The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed 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. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long term license agreements. The Partnership recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license. As of September 30, 2018, the Partnership had $383 million in deferred revenues representing the current value of our future performance obligations.

The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis.

The opening and closing balances of Sunoco LP’s contract assets and contract liabilities are as follows:



	Balance at January 1, 2018		Balance at September 30, 2018		Increase
Contract Balances
Contract Asset	$	51	$	66	$	15
Accounts receivable from contracts with customers	445		582		137
Contract Liability	1		1		—

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 the service is provided. 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.

Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately nine years, with an estimated, volume-weighted term remaining of approximately four years.

As part of the asset purchase agreement with 7-Eleven, Sunoco LP and 7-Eleven and SEI Fuel (collectively, the “Distributor”) have entered into a 15-year take-or-pay fuel supply agreement in which the Distributor is required to purchase a volume of

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fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall Sunoco LP will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations.

In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.

As of September 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $41.68 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	$	1,474	$	5,258	$	4,696	$	30,256	$	41,684

Costs to Obtain or Fulfill a Contract

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

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.

•

Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.


•	Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.

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•	Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.).


•	Variable consideration of wholly unsatisfied performance obligations: The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations.

13. DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. 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 operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. 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 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 operations 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 operations, 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, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	358		2018-2019	1,078		2018
Basis Swaps IFERC/NYMEX ⁽¹⁾	69,685		2018-2020	48,510		2018-2020
Options – Puts	(17,273	)	2019	13,000		2018
Power (Megawatt):
Forwards	429,720		2018-2019	435,960		2018-2019
Futures	309,123		2018-2019	(25,760	)	2018
Options — Puts	157,435		2018-2019	(153,600	)	2018
Options — Calls	321,240		2018-2019	137,600		2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(7,705	)	2018-2021	4,650		2018-2020
Swing Swaps IFERC	69,145		2018-2019	87,253		2018-2019
Fixed Swaps/Futures	(1,834	)	2018-2020	(4,390	)	2018-2019
Forward Physical Contracts	(54,151	)	2018-2020	(145,105	)	2018-2020
NGL (MBbls) – Forwards/Swaps	(4,937	)	2019	(2,493	)	2018-2019
Crude (MBbls) – Forwards/Swaps	35,228		2018-2019	9,237		2018-2019
Refined Products (MBbls) – Futures	(1,507	)	2018-2019	(3,901	)	2018-2019
Corn (thousand bushels)	(3,100	)	2018-2019	1,870		2018
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	2018-2019	(39,770	)	2018
Fixed Swaps/Futures	(21,475	)	2018-2019	(39,770	)	2018
Hedged Item — Inventory	21,475		2018-2019	39,770		2018


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

Interest Rate Risk

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



		Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2018		December 31, 2017
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	$	—	$	300
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	400		300
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		400
July 2021⁽²⁾	Forward-starting to pay a fixed rate of 3.55% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300


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


⁽²⁾	Represents the effective date. These forward-starting swaps have a term 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 our 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, we may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implements the use of industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

We have 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
	Asset Derivatives				Liability Derivatives
	September 30, 2018		December 31, 2017		September 30, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	14	$	(6	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	477		262		(537		)	(281		)
Commodity derivatives	126		45		(334		)	(58		)
Interest rate derivatives	—		—		(97		)	(219		)
	603		307		(968		)	(558		)
Total derivatives	$	603	$	321	$	(974	)	$	(560	)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(97	)	$	(219	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	126			45			(334		)	(58		)
Broker cleared derivative contracts	Other current assets (liabilities)	477			276			(543		)	(283		)
Total gross derivatives		603			321			(974		)	(560		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(29		)	(21		)	29			21
Counterparty netting	Other current assets (liabilities)	(477		)	(263		)	477			263
Total net derivatives		$	97		$	37		$	(468	)	$	(276	)

We disclose the non-exchange traded financial derivative instruments as price risk management 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 with respect to our derivative financial instruments:



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



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2018		2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	3	$	(5	)	$	36		$	21
Commodity derivatives — Non-trading	Cost of products sold	21		(25		)	(345		)	(6		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	45		(8		)	117			(28		)
Embedded derivatives	Other, net	—		—			—			1
Total		$	69	$	(38	)	$	(192	)	$	(12	)

14. RELATED PARTY TRANSACTIONS

Revenues reported in our consolidated statements of operations included sales with affiliates of $103 million and $105 million during the three months ended September 30, 2018 and 2017, respectively, and $325 million and $201 million during the nine months ended September 30, 2018 and 2017, respectively.

15. REPORTABLE SEGMENTS

Our financial statements reflect the following reportable business segments:


•	Investment in ETP, including the consolidated operations of ETP;


•	Investment in Sunoco LP, including the consolidated operations of Sunoco LP;


•	Investment in USAC, including the consolidated operations of USAC;


•	Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and


•	Corporate and Other, including the following:


•	activities of the Parent Company; and


•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

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The Investment in USAC segment reflects the results of USAC beginning April 2018, the date that ETE obtained control of USAC. Also beginning April 2018, ETP holds an equity method investment in USAC, the equity in earnings from which is eliminated in ETE’s consolidated financial statements.

The CDM entities were consolidated subsidiaries of ETP prior to April 2018 and are consolidated subsidiaries of USAC beginning April 2018. Therefore, the results of the CDM entities are included in the Investment in ETP segment prior to April 2018 and in the Investment in USAC segment thereafter.

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, gain on deconsolidation 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). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations.

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The following tables present financial information by segment:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Investment in ETP	$	2,329		$	1,784		$	6,261		$	4,774
Investment in Sunoco LP	208			199			457			574
Investment in USAC	90			—			185			—
Investment in Lake Charles LNG	43			43			131			131
Corporate and Other	(9		)	(3		)	(17		)	(25		)
Adjustments and Eliminations	(84		)	(74		)	(176		)	(211		)
Total	2,577			1,949			6,841			5,243
Depreciation, depletion and amortization	(750		)	(642		)	(2,109		)	(1,877		)
Interest expense, net of interest capitalized	(535		)	(490		)	(1,511		)	(1,440		)
Impairment losses	—			(10		)	—			(99		)
Gains (losses) on interest rate derivatives	45			(8		)	117			(28		)
Non-cash compensation expense	(27		)	(29		)	(82		)	(76		)
Unrealized gains (losses) on commodity risk management activities	97			(76		)	(255		)	22
Gains on disposal of assets	18			5			14			—
Losses on extinguishments of debt	—			—			(106		)	(25		)
Inventory valuation adjustments	(7		)	50			50			8
Equity in earnings of unconsolidated affiliates	87			92			258			228
Adjusted EBITDA related to unconsolidated affiliates	(179		)	(205		)	(503		)	(554		)
Adjusted EBITDA related to discontinued operations	—			(76		)	25			(179		)
Other, net	15			24			45			76
Income from continuing operations before income tax (expense) benefit	1,341			584			2,784			1,299
Income tax (expense) benefit from continuing operations	52			157			(6		)	86
Income from continuing operations	1,393			741			2,778			1,385
Income (loss) from discontinued operations, net of income taxes	(2		)	17			(265		)	(187		)
Net income	$	1,391		$	758		$	2,513		$	1,198

* As adjusted. See Note 1.



	September 30, 2018			December 31, 2017
Assets:
Investment in ETP	$	79,156		$	77,965
Investment in Sunoco LP	5,148			8,344
Investment in USAC	3,814			—
Investment in Lake Charles LNG	1,746			1,646
Corporate and Other	625			598
Adjustments and Eliminations	(2,302		)	(2,307		)
Total assets	$	88,187		$	86,246

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017*			2018			2017*
Revenues:
Investment in ETP:
Revenues from external customers	$	9,538		$	6,876		$	26,921		$	20,168
Intersegment revenues	103			97			410			276
	9,641			6,973			27,331			20,444
Investment in Sunoco LP:
Revenues from external customers	4,760			3,058			13,114			8,755
Intersegment revenues	1			6			3			9
	4,761			3,064			13,117			8,764
Investment in USAC:
Revenues from external customers	166			—			331			—
Intersegment revenues	3			—			5			—
	169			—			336			—
Investment in Lake Charles LNG:
Revenues from external customers	50			49			148			148

Adjustments and Eliminations	(107		)	(102		)	(418		)	(284		)
Total revenues	$	14,514		$	9,984		$	40,514		$	29,072

* As adjusted. See Note 1.

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP, USAC and Lake Charles LNG.

Investment in ETP



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017*		2018		2017*
Intrastate transportation and storage	$	846	$	729	$	2,424	$	2,196
Interstate transportation and storage	390		220		1,026		652
Midstream	537		665		1,571		1,863
NGL and refined products transportation and services	2,948		1,989		7,878		5,874
Crude oil transportation and services	4,422		2,714		12,942		7,749
All Other	498		656		1,490		2,110
Total revenues	9,641		6,973		27,331		20,444
Less: Intersegment revenues	103		97		410		276
Revenues from external customers	$	9,538	$	6,876	$	26,921	$	20,168

* As adjusted. See Note 1.

The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger.

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Investment in Sunoco LP



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Fuel distribution and marketing	$	4,494	$	2,467	$	11,983	$	7,082
All other	267		597		1,134		1,682
Total revenues	4,761		3,064		13,117		8,764
Less: Intersegment revenues	1		6		3		9
Revenues from external customers	$	4,760	$	3,058	$	13,114	$	8,755

Investment in USAC



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Contract operations	$	163	$	—	$	323	$	—
Retail parts and services	5		—		11		—
Station installations revenue	1		—		2		—
Total revenues	169		—		336		—
Less: Intersegment revenues	3		—		5		—
Revenues from external customers	$	166	$	—	$	331	$	—

USAC’s revenues for all periods presented were related to the compression services business.

Investment in Lake Charles LNG

Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling.

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16. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

(unaudited)



	September 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	1
Accounts receivable from related companies	100			65
Other current assets	1			1
Total current assets	102			67
Property, plant and equipment, net	27			27
Advances to and investments in unconsolidated affiliates	6,045			6,082
Goodwill	9			9
Other non-current assets, net	7			8
Total assets	$	6,190		$	6,193
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Accounts payable to related companies	$	42		$	—
Interest payable	78			66
Accrued and other current liabilities	9			4
Total current liabilities	129			70
Long-term debt, less current maturities	6,415			6,700
Long-term notes payable – related companies	747			617
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ deficit:
Limited Partners:
Series A Convertible Preferred Units	—			450
Common Unitholders	(1,099		)	(1,643		)
General Partner	(4		)	(3		)
Total partners’ deficit	(1,103		)	(1,196		)
Total liabilities and partners’ deficit	$	6,190		$	6,193

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(9	)	$	(3	)	$	(20	)	$	(25	)
OTHER INCOME (EXPENSE):
Interest expense, net	(89		)	(88		)	(265		)	(257		)
Equity in earnings of unconsolidated affiliates	469			343			1,359			1,012
Losses on extinguishments of debt	—			—			—			(25		)
Other, net	—			—			3			(2		)
NET INCOME	371			252			1,077			703
Convertible Unitholders’ interest in income	—			11			33			25
General Partner’s interest in net income	1			1			3			2
Limited Partners’ interest in net income	$	370		$	240		$	1,041		$	676

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STATEMENTS OF CASH FLOWS

(unaudited)



	Nine Months Ended September 30,
	2018			2017
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	993		$	620
CASH FLOWS FROM INVESTING ACTIVITIES
Contributions to unconsolidated affiliate	(250		)	(861		)
Capital expenditures	—			(1		)
Contributions in aid of construction costs	—			7
Sunoco LP Series A Preferred Units redemption	303			—
Net cash provided by (used in) investing activities	53			(855		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	413			2,116
Principal payments on debt	(703		)	(1,795		)
Proceeds from affiliate	130			131
Distributions to partners	(886		)	(752		)
Units issued for cash	—			568
Debt issuance costs	—			(35		)
Net cash provided by (used in) financing activities	(1,046		)	233
CHANGE IN CASH AND CASH EQUIVALENTS	—			(2		)
CASH AND CASH EQUIVALENTS, beginning of period	1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	—

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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 included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 filed with the SEC on 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, 2017.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer LP (formerly Energy Transfer Equity, L.P.) and its consolidated subsidiaries, which include ETP, Sunoco LP, Lake Charles LNG, and, beginning April 2018, USAC. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

OVERVIEW

At September 30, 2018, our interests in ETP, Sunoco LP and USAC consisted of 100% of the respective general partner interests and IDRs in ETP and Sunoco LP, as well as approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units, and approximately 20.5 million USAC common units. Additionally, ETE owned 100 ETP Class I Units, which were not entitled to any distributions.

Our reportable segments are as follows:


•	Investment in ETP, including the consolidated operations of ETP;


•	Investment in Sunoco LP, including the consolidated operations of Sunoco LP;


•	Investment in USAC, including the consolidated operations of USAC;


•	Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and


•	Corporate and Other, including the following:


•	activities of the Parent Company; and


•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

RECENT DEVELOPMENTS

ETE and ETP Simplification Transaction

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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•	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


•	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.

ETE Series A Convertible Preferred Units

In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million ETE common units in accordance with the terms of ETE’s partnership agreement.

ETP 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.

ETP Series D Preferred Units Issuance

ETP Senior Notes Offering and Redemption

In June 2018, ETP issued $500 million aggregate principal amount of 4.20% senior notes due 2023, $1.00 billion aggregate principal amount of 4.95% senior notes due 2028, $500 million aggregate principal amount of 5.80% senior notes due 2038 and $1.00 billion aggregate principal amount of 6.00% senior notes due 2048. The $2.96 billion net proceeds from the offering were used to redeem outstanding senior notes, to repay borrowings outstanding under ETP’s revolving credit facility and for general partnership purposes.

Old Ocean Joint Venture Formation

In May 2018, ETP and Enterprise Products Partners L.P. announced the formation of a joint venture to resume service on the Old Ocean natural gas pipeline. The 24-inch diameter pipeline resumed service in May 2018 and ETP is the operator. Additionally, both parties are in the process of expanding their jointly owned North Texas 36-inch pipeline that will provide more capacity from West Texas for deliveries into the Old Ocean pipeline. The North Texas pipeline expansion project is expected to be complete by January 1, 2019.

Acquisition of HPC

ETP 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 $450 million. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.

ETP New Ethane Export Facility Joint Venture

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

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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 wholly own the infrastructure that is required to both supply ethane to the pipeline and to load the ethane on to very large ethane carriers (“VLECs”) 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 Retail Store and Real Estate Sales

On April 1, 2018, Sunoco LP completed the conversion of 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets to a single commission agent. Under the commission agent model, Sunoco LP owns, prices and sells fuel at the sites, paying the commission agent a fixed cents-per-gallon commission and receives rental income from the commission agent. The commission agent conducts all operations related to the retail stores and related restaurant locations.

On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven. Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.2 billion.

Sunoco LP Common Unit Repurchase

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

Sunoco LP Series A Preferred Units

Sunoco LP Private Offering of Senior Notes

On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the 7-Eleven Transaction, to: 1) redeem in full its previously existing senior notes, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate its term loan; 3) pay all closing costs in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units; and 5) repurchase 17,286,859 common units owned by ETP.

USAC Transactions

On April 2, 2018, 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 representing limited partner interests in USAC for cash consideration equal to $250 million. Concurrently, 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 USAC common units, (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

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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.

Beginning April 2018, ETE’s consolidated financial statements reflected USAC as a consolidated subsidiary.

Quarterly Cash Distribution

In October 2018, ETE announced its quarterly distribution of $0.305 per unit ($1.22 annualized) on ETE common units for the quarter ended September 30, 2018.

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 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 treatment of income taxes may have on the rates ETP can charge for the FERC regulated transportation services are unknown at this time.

The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or before May 21, 2018. It is unknown at this time what actions that the FERC will take, if any, following receipt of responses to the 2017 Tax Law NOI and any potential impacts from final rules or policy statements issued following the 2017 Tax Law NOI on the rates ETP can charge for FERC regulated transportation services.

Included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC regulated natural gas pipeline select one of four options: 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 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 rate proceeding that may impact the 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 pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. The revenues we receive from natural gas transportation services we provide pursuant to cost of service based rates may decrease in the future as a result of the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost of service rates, if any, will depend on a detailed review of all of ETP’s cost of service components and the 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 used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Liquids Transportation Regulation

The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every 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 next five year review of the liquids pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of the appropriate pipeline index. Accordingly, depending on the FERC’s application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates.

Results of Operations

We 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, gain on deconsolidation 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). Segment Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations.

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 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.

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Consolidated Results



	Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017*			Change			2018			2017*			Change
Segment Adjusted EBITDA:
Investment in ETP	$	2,329		$	1,784		$	545		$	6,261		$	4,774		$	1,487
Investment in Sunoco LP	208			199			9			457			574			(117		)
Investment in USAC	90			—			90			185			—			185
Investment in Lake Charles LNG	43			43			—			131			131			—
Corporate and Other	(9		)	(3		)	(6		)	(17		)	(25		)	8
Adjustments and Eliminations	(84		)	(74		)	(10		)	(176		)	(211		)	35
Total	2,577			1,949			628			6,841			5,243			1,598
Depreciation, depletion and amortization	(750		)	(642		)	(108		)	(2,109		)	(1,877		)	(232		)
Interest expense, net of interest capitalized	(535		)	(490		)	(45		)	(1,511		)	(1,440		)	(71		)
Impairment losses	—			(10		)	10			—			(99		)	99
Gains (losses) on interest rate derivatives	45			(8		)	53			117			(28		)	145
Non-cash compensation expense	(27		)	(29		)	2			(82		)	(76		)	(6		)
Unrealized gains (losses) on commodity risk management activities	97			(76		)	173			(255		)	22			(277		)
Gains on disposal of assets	18			5			13			14			—			14
Losses on extinguishments of debt	—			—			—			(106		)	(25		)	(81		)
Inventory valuation adjustments	(7		)	50			(57		)	50			8			42
Equity in earnings of unconsolidated affiliates	87			92			(5		)	258			228			30
Adjusted EBITDA related to unconsolidated affiliates	(179		)	(205		)	26			(503		)	(554		)	51
Adjusted EBITDA related to discontinued operations	—			(76		)	76			25			(179		)	204
Other, net	15			24			(9		)	45			76			(31		)
Income from continuing operations before income tax (expense) benefit	1,341			584			757			2,784			1,299			1,485
Income tax (expense) benefit from continuing operations	52			157			(105		)	(6		)	86			(92		)
Income from continuing operations	1,393			741			652			2,778			1,385			1,393
(Loss) gain from discontinued operations, net of income taxes	(2		)	17			(19		)	(265		)	(187		)	(78		)
Net income	$	1,391		$	758		$	633		$	2,513		$	1,198		$	1,315

* As adjusted.

See the detailed discussion of Segment Adjusted EBITDA in “Segment Operating Results” below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and nine months ended September 30, 2018 compared to the same period last year increased primarily due to additional depreciation and amortization from assets recently placed in service.

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Interest Expense, Net. Interest expense for the three and nine months ended September 30, 2018 increased primarily due to the following:


•	increases of $35 million and $71 million, respectively, of expense recognized by ETP compared to the same periods in the prior year primarily attributable to increases in long-term debt from ETP senior note issuances partially offset by a decrease in credit facility borrowings; and


•	increases of $1 million and $8 million, respectively, of expense recognized by the Parent company compared to the same periods in the prior year primarily attributable to increases in variable interest rates;


•	an increase of $25 million and $51 million, respectively, due to the consolidation of USAC beginning April 2, 2018; partially offset by


•	decreases of $16 million and $58 million, respectively, of expense recognized by Sunoco LP compared to the same periods in the prior year primarily due to Sunoco LP’s repayment in full of its term loan and decreased borrowings under its revolving credit facility.

Gains (Losses) on Interest Rate Derivatives. Gains on interest rate derivatives during the three and nine months ended September 30, 2018 and September 30, 2017 resulted from 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 the segment results below.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded during the three and nine months ended September 30, 2018 and 2017, for inventory associated with Sunoco LP’s fuel distribution and marketing operations.

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.

Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that was classified as held for sale.

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

Income Tax (Expense) Benefit. For the three and nine months ended September 30, 2018 compared to the same periods last year, the Partnership’s income tax benefit decreased primarily due to higher pre-tax income from our corporate subsidiaries, which was partially offset by the decrease in federal corporate income tax rate per the Tax Act as well as a state statutory rate reduction.

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Segment Operating Results

Investment in ETP

Our Investment in ETP reflects the consolidated operations of ETP prior to the ETE-ETP Merger in October 2018.



	Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017*			Change			2018			2017*			Change
Revenues	$	9,641		$	6,973		$	2,668		$	27,331		$	20,444		$	6,887
Cost of products sold	(6,745		)	(4,922		)	(1,823		)	(19,873		)	(14,595		)	(5,278		)
Unrealized (gains) losses on commodity risk management activities	(97		)	81			(178		)	255			(17		)	272
Operating expenses, excluding non-cash compensation expense	(621		)	(525		)	(96		)	(1,823		)	(1,543		)	(280		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(111		)	(95		)	(16		)	(310		)	(302		)	(8		)
Adjusted EBITDA related to unconsolidated affiliates	257			279			(22		)	670			765			(95		)
Other, net	5			(7		)	12			11			22			(11		)
Segment Adjusted EBITDA	$	2,329		$	1,784		$	545		$	6,261		$	4,774		$	1,487

* As adjusted.

Segment Adjusted EBITDA. For the three months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP segment increased due to the net impact of the following:

•

an increase of $58 million in ETP’s intrastate transportation and storage operations resulting from an increase of $55 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity; a net increase of $6 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above; and an increase of $7 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; partially offset by a decrease of $5 million in realized storage margin primarily due to lower realized derivative gains;

•

an increase of $143 million in ETP’s interstate transportation and storage operations due to an increase of $128 million associated with the initiation of service on the Rover pipeline with increases of $149 million in revenues, $14 million in operating expenses and $7 million in general and administrative expenses; and an increase of $22 million in revenues, excluding the incremental revenue from Rover pipeline, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines; partially offset by an increase of $4 million in operating expenses, excluding the incremental expenses from Rover pipeline, primarily due to slightly higher system gas expense and higher maintenance project costs due to scope and level of activity; and decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily related to sale of capacity on MEP at lower rates and lower sales of short term firm capacity on Citrus;

•

an increase of $78 million in ETP’s midstream operations primarily due to a $53 million increase in non-fee-based margins mainly due to higher realized crude oil and NGL prices and increased throughput in the Permian region; a $38 million increase in fee-based revenues due to growth in the North Texas, Permian and Northeast regions offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions; a decrease of $7 million in selling, general and administrative expenses primarily due to a decrease of $3 million in merger and acquisition costs and a $3 million change in capitalized overhead; and an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from ETP’s Aqua, Mi Vida and Ranch joint ventures; partially offset by an increase of $22 million in operating expenses primarily due to increases of $6 million in materials, $5 million in outside services and $4 million in maintenance project costs, as well as a $7 million change in capitalized overhead;

•

an increase of $59 million in ETP’s NGL and refined products transportation and services operations due to an increase of $76 million in transportation volume, primarily due to a $63 million increase from higher volumes from the Permian region on ETP’s Texas NGL pipelines, an increase of $11 million increase due to higher throughput volumes on Mariner West driven by end user facility constraints in the prior period, an increase of $8 million increase due to higher throughput volumes from the Eagle Ford and Barnett regions, a $3 million increase due to higher throughput volumes in ETP’s Northeast refined products

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system and a $3 million increase due to higher throughput volumes on Mariner South and Mariner East 1 NGL systems, 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 due to a $40 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 $4 million increase from Mariner South as 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, 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 a $25 million increase 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 allocations, $6 million due to environmental reserves and $5 million due to ad valorem tax expense; and a $21 million decrease in marketing margin primarily due to a $13 million decrease in optimization gains from ETP’s Mont Belvieu marketing activities, a $4 million decrease from sales of propane and other products at ETP’s Marcus Hook Industrial Complex and a $2 million decrease from ETP’s butane blending operations resulting from a decrease in blending volumes;

•

an increase of $262 million in ETP’s crude oil transportation and services operations primarily due to an increase of $131 million resulting primarily from ETP’s Bakken pipeline and from Permian producers on existing pipeline assets, as well as a $30 million increase resulting from placing ETP’s Permian Express 3 pipeline in service in the fourth quarter of 2017, a $108 million increase (excluding a net change of $117 million in unrealized gains and losses) from ETP’s crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets, and a $10 million increase from higher throughput and 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 an increase of $7 million in operating expenses due to a $5 million increase from higher throughput related expenses on existing assets and a $2 million increase from placing ETP’s Permian Express 3 pipeline in service in the fourth quarter 2017; and

•

a decrease of $55 million in ETP’s all other operations due to a decrease of $16 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in Sunoco LP resulting from the 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 the contribution of CDM to USAC in April 2018, which decrease reflects the impact of ETP deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; a decrease of $12 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in PES primarily due to ETP’s lower ownership in PES subsequent to its reorganization in August 2018, subsequent to which PES is no longer reflected as an affiliate; an increase of $7 million in general and administrative expenses from higher professional expenses; a decrease of $6 million due to losses from commodity trading and risk management activities; and a decrease of $3 million primarily due to lower margin from ETP’s compression equipment business.

Segment Adjusted EBITDA. For the nine months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP segment increased due to the net impact of the following:

•

an increase of $141 million in ETP’s intrastate transportation and storage operations resulting from an increase of $160 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity; a net increase of $3 million due to the consolidation of RIGS beginning in April 2018, as discussed in “Recent Developments” above; and an increase of $6 million in transportation fees, excluding the impact of consolidating RIGS, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; 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;

•

an increase of $269 million in ETP’s interstate transportation and storage operations due to an increase of $247 million associated with the initiation of service on the Rover pipeline with increases of $336 million in revenues, $70 million in operating expenses and $19 million in general and administrative expenses; and an increase of $45 million in revenues, excluding the incremental revenue from Rover pipeline, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $8 million of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by increase of $6 million in operating expenses, excluding the incremental expenses from Rover

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pipeline, due to higher maintenance project costs; and a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short term firm capacity on Citrus and lower margins on MEP due to lower rates on renewals of expiring long term contracts, partially offset by lower legal fees on Citrus;

•

an increase of $137 million in ETP’s midstream operations primarily due to a $104 million increase in non-fee-based margins due to higher realized crude oil and NGL prices and increased throughput in the North Texas and Permian regions; a $68 million increase 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 $5 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from ETP’s Aqua, Mi Vida and Ranch joint ventures; and a decrease of $1 million in selling, general and administrative expenses primarily due to lower office expenses; partially offset by an increase of $42 million in operating expenses primarily due to outside services, materials expense, and employee costs;

•

an increase of $202 million in ETP’s NGL and refined products transportation and services operations due to an increase of $158 million in transportation margin due to a $141 million 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 Mariner West driven by end user facility constraints in the prior period, an $11 million increase resulting from a reclassification between ETP’s transportation and fractionation margins in the second quarter of 2018, a $4 million increase due to higher throughput volumes from the Barnett region, a $4 million increase due to higher throughput volumes from ETP’s Northeast and Southwest refined product systems and a $4 million increase due to higher throughput volumes on Mariner South due to system downtime in the prior period, partially offset by a $16 million decrease resulting from lower throughput on Mariner 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, 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, 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 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, $4 million due to the timing of maintenance projects and higher overhead costs and $10 million due to environmental reserves; 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;

•

an increase of $859 million in ETP’s crude oil transportation and services operations primarily due to a $541 million increase resulting primarily from placing ETP’s Bakken pipeline in service in the second quarter of 2017, a $86 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets, a $295 million increase (excluding a net change of $190 million in unrealized gains and losses) from ETP’s crude oil acquisition and marketing business primarily resulting from more favorable market price differentials between the West Texas and Gulf Coast markets, and a $25 million increase primarily from ETP’s Nederland facility due to higher ship loading fees as a result of increased exports; and an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to increased jet fuel sales from one of ETP’s joint ventures; partially offset by an increase of $92 million in operating expenses with $37 million due to assets recently placed in service, as well as $36 million from higher expenses on existing assets and $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 a $4 million increase from ad valorem taxes; partially offset by an $11 million decrease in insurance and environmental related expenses; and


•	a decrease of $121 million in ETP’s all other operations due to a decrease of $85 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in Sunoco LP resulting from ETP’s lower ownership in Sunoco LP and lower operating results of Sunoco LP due to the sale of the majority of its retail assets in January 2018; a decrease of $31 million

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in Adjusted EBITDA related to unconsolidated affiliates primarily from ETP’s investment in PES primarily resulting from ETP’s lower ownership in PES subsequent to its reorganization in August 2018, subsequent to which PES is no longer reflected as an affiliate; and a decrease of $21 million due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of ETP deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by a decrease of $10 million in Adjusted EBITDA primarily due to lower transport fees of $6 million resulting from the expiration of a capacity commitment on ETP’s Trunkline pipeline and a $7 million decrease in losses from the mark-to-market of physical system gas, offset by lower optimization gains on residue gas sales; an increase of $6 million from increased margin from ETP’s compression equipment business as several larger projects were completed in June 2018; and an increase of $4 million due to an equipment lease buyout in August 2017, partially offset by lower margin from depressed gas prices in West Texas.

Investment in Sunoco LP



	Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Change			2018			2017			Change
Revenues	$	4,761		$	3,064		$	1,697		$	13,117		$	8,764		$	4,353
Cost of products sold	(4,428		)	(2,748		)	(1,680		)	(12,178		)	(7,933		)	(4,245		)
Unrealized gains on commodity risk management activities	—			(5		)	5			—			(5		)	5
Operating expenses, excluding non-cash compensation expense	(106		)	(116		)	10			(324		)	(343		)	19
Selling, general and administrative, excluding non-cash compensation expense	(30		)	(21		)	(9		)	(93		)	(80		)	(13		)
Inventory fair value adjustments	7			(50		)	57			(50		)	(8		)	(42		)
Adjusted EBITDA from discontinued operations	—			76			(76		)	(25		)	179			(204		)
Other	4			(1		)	5			10			—			10
Segment Adjusted EBITDA	$	208		$	199		$	9		$	457		$	574		$	(117	)

Segment Adjusted EBITDA. For the three months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:

•

an increase in gross profit of $84 million, which includes an increase in gross profit on motor fuel sales (excluding inventory fair value adjustments and unrealized gains on commodity risk management activities) of $111 million primarily due to an increase in motor fuel gallons sold, which includes a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier, partially offset by a decrease in other gross profit of $27 million primarily due to the conversion of 207 retail sites to commission agent sites in April 2018; and


•	a net decrease in operating expenses and selling, general and administrative expenses of $1 million primarily due to a decrease in salaries and benefits; offset by


•	a decrease of $76 million in Adjusted EBITDA from discontinued operations primarily attributable to Sunoco LP’s retail divestment in January 2018.

Segment Adjusted EBITDA. For the nine months ended September 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment decreased due to the net impacts of the following:


•	a decrease of $204 million in Adjusted EBITDA from discontinued operations primarily attributable to Sunoco LP’s retail divestment in January 2018; offset by

•

an increase in gross profit of $81 million, which includes an increase in gross profit on motor fuel sales (excluding inventory fair value adjustments and unrealized gains on commodity risk management activities) of $136 million primarily due to an increase in motor fuel gallons sold, which includes a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier, partially offset by a decrease in other gross profit of $55 million primarily due to the conversion of 207 retail sites to commission agent sites in April 2018; and

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•	a net decrease in operating expenses and selling, general and administrative expenses of $6 million primarily due to a decrease in rent expense and in salaries and benefits.

Investment in USAC



	Three Months Ended September 30,								Nine Months Ended September 30,
	2018			2017		Change			2018			2017		Change
Revenues	$	169		$	—	$	169		$	336		$	—	$	336
Cost of products sold	(24		)	—		(24		)	(44		)	—		(44		)
Operating expenses, excluding non-cash compensation expense	(42		)	—		(42		)	(80		)	—		(80		)
Selling, general and administrative, excluding non-cash compensation expense	(15		)	—		(15		)	(34		)	—		(34		)
Other	2			—		2			7			—		7
Segment Adjusted EBITDA	$	90		$	—	$	90		$	185		$	—	$	185

Amounts reflected above for the three and nine months ended September 30, 2018 represent the results of operations for USAC from April 2, 2018, the date ETE obtained control of USAC, through September 30, 2018. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.

Investment in Lake Charles LNG



	Three Months Ended September 30,									Nine Months Ended September 30,
	2018			2017			Change			2018			2017			Change
Revenues	$	50		$	49		$	1		$	148		$	148		$	—
Operating expenses, excluding non-cash compensation expense	(6		)	(6		)	—			(15		)	(15		)	—
Selling, general and administrative, excluding non-cash compensation expense	(1		)	—			(1		)	(2		)	(2		)	—
Segment Adjusted EBITDA	$	43		$	43		$	—		$	131		$	131		$	—

Lake Charles LNG derives all of its revenue from a long-term contract with Royal Dutch Shell plc.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in ETP, Sunoco LP, USAC and Lake Charles LNG. The amount of cash that ETP, Sunoco LP and USAC distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below.

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

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

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ETP

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

ETP currently expects capital expenditures in 2018 to be within the following ranges:



	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 ETP’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

The assets used in ETP’s 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, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETP experiences increases in pipe costs due to a number of reasons, including but not limited to, delays from mills, limited selection of mills capable of producing large diameter pipe in a timely manner, higher steel prices and other factors beyond ETP’s control. However, ETP included these factors in its anticipated growth capital expenditures for each year.

ETP generally funds its maintenance capital expenditures and distributions with cash flows from operating activities. ETP generally funds growth capital expenditures with proceeds of borrowings under the ETP Credit Facility, long-term debt, the issuance of additional ETP common units, dropdown proceeds or the monetization of non-core assets or a combination thereof.

Sunoco LP

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

Excluding acquisitions, Sunoco LP currently expects to spend approximately $65 million on growth capital and $30 million on maintenance capital for the full year 2018.

USAC

The compression services business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. USAC’s capital requirements have consisted primarily of, and it anticipates that its capital requirements will continue to consist primarily of, the following:


•	maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of its assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining its existing business and related operating income; and


•	expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.

USAC classifies capital expenditures as maintenance or expansion on an individual asset basis. Over the long-term, USAC expects that its maintenance capital expenditure requirements will continue to increase as the overall size and age of its fleet increase. USAC’s aggregate maintenance capital expenditures for the three and six months ended September 30, 2018 was $7 million and

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$22 million, respectively. USAC currently plans to spend approximately $30 million in maintenance capital expenditures during 2018, including parts consumed from inventory.

Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between $190 million and $200 million in expansion capital expenditures during 2018. USAC’s expansion capital expenditures for the three and six months ended September 30, 2018 was $73 million and $117 million, respectively. As of September 30, 2018, USAC has binding commitments to purchase $126 million of additional compression units and serialized parts, of which USAC expects to spend $33 million for units to be delivered in the remainder of 2018.

Cash Flows

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

Operating Activities

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

Nine months ended September 30, 2018 compared to nine months ended September 30, 2017. Cash provided by operating activities during 2018 was $5.30 billion as compared to $3.41 billion for 2017. Net income was $2.51 billion and $1.20 billion for 2018 and 2017, respectively. The difference between net income and the net cash provided by operating activities for the nine months ended September 30, 2018 and 2017, primarily consisted of non-cash items totaling $1.91 billion and $1.55 billion, respectively, and net changes in operating assets and liabilities of $423 million and $192 million, respectively.

The non-cash activity in 2018 and 2017 consisted primarily of depreciation, depletion and amortization of $2.11 billion and $1.88 billion, respectively, equity in earnings of unconsolidated affiliates of $258 million and $228 million, respectively, inventory valuation adjustments of $50 million and $8 million, respectively, deferred income taxes of $1 million and $64 million, respectively, losses on extinguishments of debt of $106 million and $25 million, respectively, and non-cash compensation expense of $82 million and $76 million, respectively.

Cash paid for interest, net of interest capitalized, was $1.41 billion and $1.37 billion for the nine months ended September 30, 2018 and 2017, respectively.

Capitalized interest was $222 million and $215 million for the nine months ended September 30, 2018 and 2017, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, and cash contributions to our joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in growth capital expenditures to fund their respective construction and expansion projects.

Nine months ended September 30, 2018 compared to nine months ended September 30, 2017. Cash used in investing activities during 2018 was $4.76 billion as compared to cash used in investing activities $4.79 billion for 2017. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2018 were $5.08 billion. This compares to total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2017 of $6.10 billion. In 2018 and 2017, we paid net cash for acquisitions of $233 million and $573 million, respectively, including the acquisition of a noncontrolling interest. In 2018, we had proceeds from the USAC transaction of $461 million. In 2017, we had proceeds from the sale of a minority interest in the Bakken Pipeline of $2.00 billion. In 2018 and 2017, we contributed $13 million and $230 million, respectively, to unconsolidated affiliates.

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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 acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.

Nine months ended September 30, 2018 compared to nine months ended September 30, 2017. Cash used in financing activities during 2018 was $3.21 billion as compared to cash provided by financing activities of $1.30 billion for 2017. In 2018, ETE received $1.40 billion in net proceeds from offerings of subsidiary common units and warrants as compared to $2.20 billion in 2017. During 2018, we had a consolidated net decrease in our debt level of $1.20 billion as compared to a net increase of $1.45 billion for 2017. In 2017, we paid net proceeds on affiliates notes in the amount of $255 million. We have paid distributions of $886 million and $752 million to our partners in 2018 and in 2017, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $2.74 billion and $2.16 billion in 2018 and 2017, respectively. We paid $188 million and $85 million in debt issuance costs in 2018 and 2017, respectively. In addition, we have received capital contributions of $438 million in cash from noncontrolling interests in 2018 compared to $919 million in 2017.

Discontinued Operations

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

Nine months ended September 30, 2018 compared to nine months ended September 30, 2017

Cash provided by discontinued operations during 2018 was $2.74 billion, resulting from cash used in operating activities of $480 million, cash provided by investing activities of $3.21 billion and changes in cash included in current assets held for sale of $11 million. Cash provided by discontinued operations during 2017 was $80 million, resulting from cash provided by operating activities of $139 million, cash used in investing activities of $57 million and changes in cash included in current assets held for sale of $2 million.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	September 30, 2018			December 31, 2017
Parent Company Indebtedness:
ETE Senior Notes due October 2020	$	1,187		$	1,187
ETE Senior Notes due March 2023	1,000			1,000
ETE Senior Notes due January 2024	1,150			1,150
ETE Senior Notes due June 2027	1,000			1,000
ETE Senior Secured Term Loan due February 2, 2024	1,220			1,220
ETE Senior Secured Revolving Credit Facility due March 24, 2022	898			1,188
Subsidiary Indebtedness:
ETP Senior Notes ⁽¹⁾	28,755			27,005
Transwestern Senior Notes	575			575
Panhandle Senior Notes	386			785
Sunoco LP Senior Notes, Term Loan and lease-related obligation	2,309			3,556
USAC Senior Notes	725			—
Credit Facilities and Commercial Paper:
ETP $5.0 billion Revolving Credit Facility due December 2023 ⁽²⁾	1,780			2,292
ETP $1.0 billion 364-Day Credit Facility due November 2019	—			50
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			2,500
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019	—			765
Sunoco LP $1.5 billion Revolving Credit Facility due July 2023	493			—
USAC $1.6 billion Revolving Credit Facility due April 2023	1,022			—
Other Long-Term Debt	5			8
Unamortized premiums and fair value adjustments, net	25			50
Deferred debt issuance costs	(258		)	(247		)
Total	44,772			44,084
Less: Current maturities of long-term debt	2,655			413
Long-term debt and notes payable, less current maturities	$	42,117		$	43,671


⁽¹⁾	Includes $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019 and $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019 that were classified as long-term as of September 30, 2018 as management has the intent and ability to refinance the borrowings on a long-term basis.


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

Sunoco LP Senior Notes and Term Loan

On January 23, 2018, Sunoco LP completed a private offering of $2.20 billion of senior notes, comprised of $1.00 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the asset purchase agreement with 7-Eleven to:


•	redeem in full its existing senior notes, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023;


•	repay in full and terminate its term loan;


•	pay all closing costs in connection with the 7-Eleven transaction;


•	redeem the outstanding Sunoco LP Series A Preferred Units; and

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•	repurchase 17,286,859 common units owned by ETP.

USAC Senior Notes

ETE Revolving Credit Facility

ETP Senior Notes Offering and Redemption

In June 2018, ETP issued the following senior notes:


•	$500 million aggregate principal amount of 4.20% senior notes due 2023;


•	$1.00 billion aggregate principal amount of 4.95% senior notes due 2028;


•	$500 million aggregate principal amount of 5.80% senior notes due 2038; and


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


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


•	Panhandle’s $400 million aggregate principal amount of 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.

ETP Five-Year Credit Facility

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ETP 364-Day Facility

ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) previously allowed for unsecured borrowings up to $1.0 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.

Bakken Credit Facility

In August 2016, ETP and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50 billion credit facility matures in August 2019 (the “Bakken Credit Facility”). As of September 30, 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 3.85%.

Sunoco LP Credit Facility

USAC Credit Facility

USAC currently has a $1.6 billion revolving credit facility, which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity.

As of September 30, 2018, USAC had $1.02 billion of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of September 30, 2018, USAC had $578 million of availability under its credit facility.

Covenants Related to Our Credit Agreements

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

CASH DISTRIBUTIONS

Cash Distributions Paid by the Parent Company

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

Distributions declared and/or paid subsequent to December 31, 2017 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017 (1)	February 8, 2018	February 20, 2018	$	0.3050
March 31, 2018 (1)	May 7, 2018	May 21, 2018	0.3050
June 30, 2018	August 6, 2018	August 20, 2018	0.3050
September 30, 2018	November 8, 2018	November 19, 2018	0.3050

⁽¹⁾

Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forgo their cash distributions on all or a portion of their common units, and in lieu of receiving cash distributions on these common units for each such quarter, such unitholder received Series A Convertible Preferred Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Series A Convertible Preferred Unit. The quarter ended March 31, 2018 was the final quarter of participation in the plan.

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Distributions declared and/or paid with respect to our Series A Convertible Preferred Units subsequent to December 31, 2017 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017	February 8, 2018	February 20, 2018	$	0.1100
March 31, 2018	May 7, 2018	May 21, 2018	0.1100

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



	Nine Months Ended September 30,
	2018		2017
Limited Partners	$	1,416	$	757
General Partner interest	3		2
Total Parent Company distributions	$	1,419	$	759

Cash Distributions Received by the Parent Company

The Parent Company’s cash available for distributions historically has been primarily generated from its direct and indirect interests in ETP and Sunoco LP. USAC and Lake Charles LNG also contribute to the Parent Company’s cash available for distributions.

The total amount of distributions to the Parent Company from its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is as follows:



	Nine Months Ended September 30,
	2018			2017
Distributions from ETP:
Limited Partner interests	$	31		$	45
General partner interest and IDRs	900			1,216
IDR relinquishments net of Class I Unit distributions	(84		)	(482		)
Total distributions from ETP	847			779
Distributions from Sunoco LP
Limited Partner interests	6			6
IDRs	52			62
Series A Preferred	2			15
Total distributions from Sunoco LP	60			83
Distributions from USAC
Limited Partner interests	22			—
Total distributions from USAC	22			—
Total distributions received from subsidiaries	$	929		$	862

Cash Distributions Paid by Subsidiaries

ETP, Sunoco LP, and USAC are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

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Cash Distributions Paid by ETP

Distributions declared and/or paid by ETP subsequent to December 31, 2017 but prior to the closing of the ETE-ETP Merger as discussed in Note 1 were as follows:



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

Distributions on ETP preferred units declared and paid by ETP subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
ETP 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
ETP 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
ETP 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
ETP Series D Preferred Units
September 30, 2018	November 1, 2018	November 15, 2018	0.5931

Cash Distributions Paid by Sunoco LP

Distributions declared and/or paid by Sunoco LP subsequent to December 31, 2017 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2017	February 6, 2018	February 14, 2018	$	0.8255
March 31, 2018	May 7, 2018	May 15, 2018	0.8255
June 30, 2018	August 7, 2018	August 15, 2018	0.8255
September 30, 2018	November 6, 2018	November 14, 2018	0.8255

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



	Nine Months Ended September 30,
	2018		2017
Limited Partners:
Common units held by public	$	134	$	133
Common and subordinated units held by ETP	65		108
Common and subordinated units held by ETE	6		6
General Partner interest and incentive distributions	52		62
Series A Preferred	2		15
Total distributions declared	$	259	$	324

Cash Distributions Paid by USAC

The following are distributions declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018:



Quarter Ended	Record Date	Payment Date	Rate
March 31, 2018	May 1, 2018	May 11, 2018	$	0.5250
June 30, 2018	July 30, 2018	August 10, 2018	0.5250
September 30, 2018	October 29, 2018	November 09, 2018	0.5250

The total amounts of USAC distributions declared since the date of acquisition were follows (all from Available Cash from USAC’s operating surplus and are shown in the period with respect to which they relate):



	Nine Months Ended September 30,
	2018
Limited Partners:
Common units held by public and other	$	90
Common units held by ETP	30
Common held by ETE	22
Total distributions declared	$	142

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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 related to revenue recognition.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 in the accompanying unaudited interim consolidated financial statements included in “Item 1. Financial Statements” in this Quarterly Report for information regarding recent accounting pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 filed with the SEC on 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 in our Annual Report on Form 10-K for the year ended December 31, 2017. Since December 31, 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. Dollar amounts are presented in millions.



	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
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	358		$	—		$	—	1,078		$	—		$	—
Basis Swaps IFERC/NYMEX ⁽¹⁾	69,685		8			1		48,510		2			1
Options – Puts	(17,273	)	—			—		13,000		—			—
Power (Megawatt):
Forwards	429,720		6			—		435,960		1			1
Futures	309,123		(1		)	1		(25,760	)	—			—
Options — Puts	157,435		1			—		(153,600	)	—			1
Options — Calls	321,240		—			—		137,600		—			—
Crude (MBbls) – Futures	—		—			—		—		1			—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(7,705	)	(45		)	14		4,650		(13		)	4
Swing Swaps IFERC	69,145		—			2		87,253		(2		)	1
Fixed Swaps/Futures	(1,834	)	1			1		(4,390	)	(1		)	2
Forward Physical Contracts	(54,151	)	5			—		(145,105	)	6			41
NGL (MBbls) – Forwards/Swaps	(4,937	)	(46		)	22		(2,493	)	5			16
Crude (MBbls) – Forwards/Swaps	35,228		(191		)	157		9,237		(4		)	9
Refined Products (MBbls) – Futures	(1,507	)	(6		)	11		(3,901	)	(27		)	4
Corn (thousand bushels)	(3,100	)	—			5		1,870		—			—
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	(4		)	—		(39,770	)	(2		)	—
Fixed Swaps/Futures	(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, 2018, we and our subsidiaries had $8.51 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $85 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding (dollars in millions), none of which are designated as hedges for accounting purposes:



		Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2018		December 31, 2017
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	$	—	$	300
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	400		300
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		400
July 2021⁽²⁾	Forward-starting to pay a fixed rate of 3.55% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300


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


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

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $239 million as of September 30, 2018. For ETP’s $1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $4 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the Chief Executive Officer (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2018 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

We acquired control of USAC on April 2, 2018 (the “USAC Transaction”) and are currently evaluating the internal control structure of USAC. We expect that evaluation to continue during the remainder of 2018. Our management reviewed the operations of USAC that are included in our results of operations. None of the changes resulting from the USAC Transaction were in response to any

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identified deficiency or weakness in our internal control over financial reporting. There were no other changes in internal control over financial reporting during the three months ended September 30, 2018.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2017 and Note 11 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2018.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed below were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.

Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II, Item 1 include any reportable legal proceeding (i) that has been terminated during the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.

On January 18, 2018, PHMSA issued a Notice of 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 (“ETC Northeast”) entered into a Consent Order and Agreement with the PADEP, pursuant to which ETC Northeast agreed to pay $150,242 to the PADEP to settle various statutory and common law claims relating to soil discharge into, and erosion of the stream bed of, Raccoon Creek in Center Township, Pennsylvania during construction of the Revolution Pipeline. ETC Northeast has paid the settlement amount and continues to monitor the construction site and work with the landowner to resolve any remaining 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 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 received NOV REG-0569-1802 for emission events that occurred January 1, 2018 through April 30, 2018 at the Jal 3 gas plant. On September 25, 2018, the New Mexico Environmental Department sent ETP a settlement offer to resolve the NOV for a penalty of $1,151,499. Negotiations for this settlement offer are ongoing.

ITEM 1A. RISK FACTORS

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

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ITEM 6. EXHIBITS

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



Exhibit Number		Description
2.1		Agreement and Plan of Merger, dated as of August 1, 2018, by and among LE GP, LLC, Energy Transfer Equity, L.P., Streamline Merger Sub, LLC, Energy Transfer Partners, L.L.C. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 to the Form 8-K filed August 3, 2018)
3.1		Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1, File No. 333-128097, filed September 2, 2005)
3.2		Certificate of Amendment of Certificate of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed October 19, 2018)
3.3		Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed February 14, 2006)
3.4		Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K, File No. 1-32740, filed November 29, 2006)
3.5		Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K, File No. 1-32740, filed November 13, 2007)
3.6		Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed June 2, 2010)
3.7		Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed December 27, 2013)
3.8		Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated March 8, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed March 9, 2016)
3.9*		Amendment No. 6 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018
10.1***		Amended and Restated Energy Transfer LP Long-Term Incentive Plan (formerly Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan) (incorporated by reference to Exhibit 10.1 of Form 10-K, File No. 1-32740, filed February 23, 2018)
10.2***		Second Amended and Restated Energy Transfer LP 2008 Long-Term Incentive Plan (formerly Second Amended and Restated Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan) (incorporated by reference to Exhibit A to the Definitive Proxy Statement on Schedule 14A filed October 24, 2014 by Energy Transfer Partners, L.P.)
10.3***		Energy Transfer LP 2011 Long-Term Incentive Plan (formerly Regency Energy Partners LP 2011 Long-Term Incentive Plan) (incorporated by reference to Exhibit A to the Definitive Proxy Statement on Schedule 14A filed November 14, 2011 by Regency Energy Partners LP)
10.4***		Energy Transfer LP Long-Term Incentive Plan, as amended and restated (formerly Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated) (incorporated by reference to Exhibit A to the Definitive Proxy Statement on Schedule 14A filed October 21, 2015 by Sunoco Logistics Partners L.P.)
10.5***		Amended and Restated Energy Transfer Partners, L.L.C. Annual Bonus Plan (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 1-32740, filed August, 9 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
31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document

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Exhibit Number		Description
101.CAL*		XBRL Taxonomy Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definitions Document
101.LAB*		XBRL Taxonomy Label Linkbase Document
101.PRE*		XBRL Taxonomy 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 LP

		By:	LE GP, LLC, its general partner

Date:	November 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)