Energy Transfer LP - Quarter Report: 2018 June (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 June 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 EQUITY, L.P.

(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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

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



Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨
		Emerging growth company	¨

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

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

At August 3, 2018, the registrant had 1,158,206,624 Common Units outstanding.

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FORM 10-Q

ENERGY TRANSFER EQUITY, L.P. 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	53

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	73

ITEM 4. CONTROLS AND PROCEDURES	75

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	77

ITEM 1A. RISK FACTORS	77

ITEM 6. EXHIBITS	88

SIGNATURE	89

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Forward-Looking Statements

Certain matters discussed in this report, as well as certain statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity” the “Partnership” or “ETE”) in periodic press releases and certain oral statements of Energy Transfer Equity 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 and “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.

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		Environmental Protection Agency

	ETP		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

	EPA		U.S. Environmental Protection Agency

	Exchange Act		Securities Exchange Act of 1934

	FERC		Federal Energy Regulatory Commission

	GAAP		accounting principles generally accepted in the United States of America

	HPC		RIGS Haynesville Partnership Co.

	IDRs		incentive distribution rights

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	Lake Charles LNG		Lake Charles LNG Company, LLC

	LIBOR		London Interbank Offered Rate

	MBbls		thousand barrels

	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 EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	June 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	519		$	336
Accounts receivable, net	4,309			4,504
Accounts receivable from related companies	106			53
Inventories	1,802			2,022
Derivative assets	63			24
Income taxes receivable	172			136
Other current assets	616			295
Current assets held for sale	6			3,313
Total current assets	7,593			10,683

Property, plant and equipment	76,409			71,177
Accumulated depreciation and depletion	(11,529		)	(10,089		)
	64,880			61,088

Advances to and investments in unconsolidated affiliates	2,687			2,705
Other non-current assets, net	996			886
Intangible assets, net	6,088			6,116
Goodwill	5,173			4,768
Total assets	$	87,417		$	86,246

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)



	June 30, 2018			December 31, 2017
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,955		$	4,685
Accounts payable to related companies	102			31
Derivative liabilities	392			111
Income taxes payable	195			—
Accrued and other current liabilities	2,832			2,582
Current maturities of long-term debt	160			413
Current liabilities held for sale	—			75
Total current liabilities	7,636			7,897

Long-term debt, less current maturities	44,473			43,671
Non-current derivative liabilities	136			145
Deferred income taxes	3,075			3,315
Other non-current liabilities	1,227			1,217

Commitments and contingencies
Redeemable noncontrolling interests	487			21

Equity:
Limited Partners:
Series A Convertible Preferred Units	—			450
Common Unitholders	(1,106		)	(1,643		)
General Partner	(4		)	(3		)
Total partners’ deficit	(1,110		)	(1,196		)
Noncontrolling interest	31,493			31,176
Total equity	30,383			29,980
Total liabilities and equity	$	87,417		$	86,246

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
REVENUES:
Natural gas sales	$	1,024		$	1,022		$	2,086		$	2,034
NGL sales	2,141			1,487			4,171			3,033
Crude sales	4,241			2,345			7,495			4,887
Gathering, transportation and other fees	1,667			1,111			3,097			2,176
Refined product sales	4,818			2,903			8,628			5,918
Other	227			559			523			1,040
Total revenues	14,118			9,427			26,000			19,088
COSTS AND EXPENSES:
Cost of products sold	11,343			7,167			20,588			14,677
Operating expenses	772			648			1,496			1,249
Depreciation, depletion and amortization	694			607			1,359			1,235
Selling, general and administrative	183			173			331			338
Impairment losses	—			89			—			89
Total costs and expenses	12,992			8,684			23,774			17,588
OPERATING INCOME	1,126			743			2,226			1,500
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(510		)	(477		)	(976		)	(950		)
Equity in earnings of unconsolidated affiliates	92			49			171			136
Losses on extinguishments of debt	—			—			(106		)	(25		)
Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Other, net	(1		)	57			56			74
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	727			347			1,443			715
Income tax expense from continuing operations	68			33			58			71
INCOME FROM CONTINUING OPERATIONS	659			314			1,385			644
Loss from discontinued operations, net of income taxes	(26		)	(193		)	(263		)	(204		)
NET INCOME	633			121			1,122			440
Less: Net income (loss) attributable to noncontrolling interest	278			(91		)	404			(11		)
NET INCOME ATTRIBUTABLE TO PARTNERS	355			212			718			451
Convertible Unitholders' interest in income	12			8			33			14
General Partner’s interest in net income	1			—			2			1
Limited Partners’ interest in net income	$	342		$	204		$	683		$	436
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.31		$	0.20		$	0.63		$	0.41
Diluted	$	0.31		$	0.19		$	0.63		$	0.40
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.31		$	0.19		$	0.62		$	0.40
Diluted	$	0.31		$	0.18		$	0.62		$	0.39

* As adjusted. See Note 1.

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)



	Three Months Ended June 30,					Six Months Ended June 30,
	2018		2017*			2018			2017*
Net income	$	633	$	121		$	1,122		$	440
Other comprehensive income, net of tax:
Change in value of available-for-sale securities	—		1			(2		)	3
Actuarial gain relating to pension and other postretirement benefit plans	—		(1		)	(2		)	(3		)
Change in other comprehensive income from unconsolidated affiliates	2		(1		)	7			(1		)
	2		(1		)	3			(1		)
Comprehensive income	635		120			1,125			439
Less: Comprehensive income attributable to noncontrolling interest	280		(92		)	407			(12		)
Comprehensive income attributable to partners	$	355	$	212		$	718		$	451

* As adjusted. See Note 1.

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE SIX MONTHS ENDED JUNE 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	—			(530		)	(2		)	—			(532		)
Distributions to noncontrolling interest	—			—			—			(1,793		)	(1,793		)
Distributions reinvested	115			(115		)	—			—			—
Subsidiary units repurchased	(7		)	(119		)	—			102			(24		)
Subsidiary units issued	—			1			—			488			489
Capital contributions received from noncontrolling interests	—			—			—			318			318
Other comprehensive income, net of tax	—			—			—			3			3
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		)	28			(1		)	17			42
Net income	33			683			2			404			1,122
Balance, June 30, 2018	$	—		$	(1,106	)	$	(4	)	$	31,493		$	30,383

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Six Months Ended June 30,
	2018			2017*
OPERATING ACTIVITIES
Net income	$	1,122		$	440
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	263			204
Depreciation, depletion and amortization	1,359			1,235
Deferred income taxes	71			59
Amortization included in interest expense	10			9
Non-cash compensation expense	55			47
Impairment losses	—			89
Loss on extinguishment of debt	106			25
Equity in earnings of unconsolidated affiliates	(171		)	(136		)
Distributions from unconsolidated affiliates	138			125
Inventory valuation adjustments	(57		)	42
Distributions on unvested awards	(25		)	(18		)
Other non-cash	(66		)	(76		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation	357			(582		)
Net cash provided by operating activities	3,162			1,463
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)	(143		)	(569		)
Capital expenditures (excluding allowance for equity funds used during construction)	(3,539		)	(2,879		)
Contributions in aid of construction costs	60			16
Contributions to unconsolidated affiliates	(13		)	(225		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	31			94
Proceeds from the sale of other assets	6			25
Other	—			1
Net cash used in by investing activities	(3,137		)	(1,537		)
FINANCING ACTIVITIES
Proceeds from borrowings	16,702			14,950
Repayments of long-term debt	(18,039		)	(14,304		)
Cash paid on affiliate notes	—			(255		)
Subsidiary units repurchased	(24		)	—
Units issued for cash	—			568
Subsidiary units and warrants issued for cash	954			462
Distributions to partners	(532		)	(501		)
Debt issuance costs	(173		)	(35		)
Distributions to noncontrolling interests	(1,793		)	(1,401		)
Capital contributions from noncontrolling interest	318			456

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	5			32
Net cash used in financing activities	(2,582		)	(81		)
DISCONTINUED OPERATIONS
Operating activities	(478		)	131
Investing activities	3,207			(62		)
Changes in cash included in current assets held for sale	11			(2		)
Net increase in cash and cash equivalents of discontinued operations	2,740			67
Increase (decrease) in cash and cash equivalents	183			(88		)
Cash and cash equivalents, beginning of period	336			467
Cash and cash equivalents, end of period	$	519		$	379

* As adjusted. See Note 1.

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)


1.	ORGANIZATION AND BASIS OF PRESENTATION

Organization

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. 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 own 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 June 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 owns 100 ETP Class I Units, which are currently not entitled to any distributions.

In August 2018, ETE and ETP announced that they have entered into a definitive agreement providing for the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange. In connection with the transaction, ETE’s IDRs in ETP will be cancelled. Under the terms of the transaction, ETP unitholders (other than ETE and its subsidiaries) will receive 1.28 common units of ETE for each common unit of ETP they own. The transaction is expected to close in the fourth quarter of 2018, subject to the approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions.

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP, Sunoco LP, USAC and cash flows from the operations of 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

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•	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 transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliate. 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, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

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 June 30, 2017									Six Months Ended June 30, 2017
	As Originally Reported*			Effect of Change			As Adjusted			As Originally Reported*			Effect of Change			As Adjusted
Cost of products sold	$	7,171		$	(4	)	$	7,167		$	14,710		$	(33	)	$	14,677
Operating income	739			4			743			1,467			33			1,500
Income before income tax expense	343			4			347			682			33			715
Net income	117			4			121			407			33			440
Net loss attributable to noncontrolling interest	(95		)	4			(91		)	(44		)	33			(11		)
Comprehensive income	116			4			120			406			33			439

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

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



	Six Months Ended June 30, 2017
	As Originally Reported*			Effect of Change			As Adjusted
Net income	$	407		$	33		$	440
Inventory Valuation Adjustments	98			(56		)	42
Net change in operating assets and liabilities (change in inventories)	(605		)	23			(582		)

* 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 ETP’s operations, as well as contracts deemed to be in-substance supply agreements in ETP’s 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 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.

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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 June 30, 2018							Six Months Ended June 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	$	1,024	$	1,024	$	—		$	2,086	$	2,086	$	—
NGL sales	2,141		2,134		7			4,171		4,153		18
Crude sales	4,241		4,238		3			7,495		7,488		7
Gathering, transportation and other fees	1,667		1,814		(147		)	3,097		3,430		(333		)
Refined product sales	4,818		4,831		(13		)	8,628		8,651		(23		)
Other	227		227		—			523		523		—

Costs and expenses:
Cost of products sold	$	11,343	$	11,491	$	(148	)	$	20,588	$	20,923	$	(335	)
Operating expenses	772		764		8			1,496		1,475		21
Depreciation and amortization	694		701		(7		)	1,359		1,372		(13		)

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	June 30, 2018
	As Reported		Balances Without Adoption of ASC 606		Effect of Change: Higher/(Lower)
Assets:
Other current assets	$	616	$	607	$	9
Property and Equipment, net	64,880		64,880		—
Intangible assets, net	6,088		6,200		(112		)
Other non-current assets, net	996		950		46

Liabilities and Equity:
Other non-current liabilities	$	1,227	$	1,226	$	1
Noncontrolling interest	31,493		31,551		(58		)

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 useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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 Topic 840. The Partnership expects to adopt ASU 2016-02 and elect the practical expedient under ASU 2018-01 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

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.

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.

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2.	ACQUISITIONS AND OTHER INVESTING TRANSACTIONS

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.

Summary of Assets Acquired and Liabilities Assumed

ETE 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.

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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 (“Amended and Restated Asset Purchase Agreement”). As a result of the purchase agreement and subsequent closing, 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 closing of the transactions contemplated by the Amended and Restated Asset Purchase Agreement, 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 six months ended June 30, 2017, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, $757 million and $1.5 billion, respectively, which were eliminated in consolidation. Sunoco LP recorded a cash inflow of $979 million and $1.6 billion from 7-Eleven in the three and six months ended June 30, 2018 since the sale related to payments on trade receivables.

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, 47 have been sold, three are under contract to be sold, and six 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:



	June 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 June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
REVENUES	$	—		$	1,757		$	349		$	3,343

COSTS AND EXPENSES
Cost of products sold	—			1,453			305			2,792
Operating expenses	—			198			61			384
Depreciation, depletion and amortization	—			3			—			36
Impairment losses	—			231			—			231
Selling, general and administrative	5			36			7			69
Total costs and expenses	5			1,921			373			3,512
OPERATING LOSS	(5		)	(164		)	(24		)	(169		)
Interest expense, net	—			4			2			8
Loss on extinguishment of debt and other	—			—			20			—
Other, net	38			3			61			8
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	(43		)	(171		)	(107		)	(185		)
Income tax expense (benefit)	(17		)	22			156			19
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	(26		)	(193		)	(263		)	(204		)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX BENEFIT ATTRIBUTABLE TO ETE	$	(1	)	$	(7	)	$	(10	)	$	(7	)

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:



	Six Months Ended June 30,
	2018			2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,015		$	1,364
Losses from subsidiary common unit transactions	(125		)	(51		)
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:



	June 30, 2018		December 31, 2017
Natural gas, NGLs, and refined products	$	873	$	1,120
Crude oil	571		551
Spare parts and other	358		351
Total inventories	$	1,802	$	2,022

ETP utilizes 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 June 30, 2018 were $44.47 billion and $44.63 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 six months ended June 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 June 30, 2018 and December 31, 2017 based on inputs used to derive their fair values:



				Fair Value Measurements at June 30, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	22		$	22		$	—
Swing Swaps IFERC	1			—			1
Fixed Swaps/Futures	11			11			—
Forward Physical Contracts	9			—			9
Power:
Forwards	69			—			69
Options — Puts	1			1			—
NGLs — Forwards/Swaps	301			301			—
Refined Products — Futures	3			3			—
Crude — Forwards/Swaps	1			1			—
Corn (Bushels)	1			1			—
Total commodity derivatives	419			340			79
Other non-current assets	21			14			7
Total assets	$	440		$	354		$	86
Liabilities:
Interest rate derivatives	$	(147	)	$	—		$	(147	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(70		)	(70		)	—
Swing Swaps IFERC	(2		)	(1		)	(1		)
Fixed Swaps/Futures	(14		)	(14		)	—
Forward Physical Contracts	(5		)	—			(5		)
Power — Forwards	(57		)	—			(57		)
NGLs — Forwards/Swaps	(319		)	(319		)	—
Refined Products — Futures	(9		)	(9		)	—
Crude — Forwards/Swaps	(308		)	(308		)	—
Total commodity derivatives	(784		)	(721		)	(63		)
Total liabilities	$	(931	)	$	(721	)	$	(210	)

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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 Swaps	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 Swaps	(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 June 30,					Six Months Ended June 30,
	2018		2017*			2018			2017*
Income from continuing operations	$	659	$	314		$	1,385		$	644
Less: Income from continuing operations attributable to noncontrolling interest	303		94			657			185
Income from continuing operations, net of noncontrolling interest	356		220			728			459
Less: Convertible Unitholders’ interest in income	12		8			33			14
Less: General Partner’s interest in income	1		—			2			1
Income from continuing operations available to Limited Partners	$	343	$	212		$	693		$	444
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,114.8		1,075.2			1,097.1			1,077.2
Basic income from continuing operations per Limited Partner unit	$	0.31	$	0.20		$	0.63		$	0.41
Basic income from discontinued operations per Limited Partner unit	$	0.00	$	(0.01	)	$	(0.01	)	$	(0.01	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	343	$	212		$	693		$	444
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	12		8			33			14
Diluted income from continuing operations available to Limited Partners	$	355	$	220		$	726		$	458
Weighted average limited partner units	1,114.8		1,075.2			1,097.1			1,077.2
Dilutive effect of unconverted unit awards and Convertible Units	43.4		66.1			61.1			66.5
Diluted weighted average limited partner units	1,158.2		1,141.3			1,158.2			1,143.7
Diluted income from continuing operations per Limited Partner unit	$	0.31	$	0.19		$	0.63		$	0.40
Diluted income from discontinued operations per Limited Partner unit	$	0.00	$	(0.01	)	$	(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

Pursuant to ETE’s revolving credit agreement, which matures on March 24, 2022, the lenders have committed to provide advances up to an aggregate principal amount of $1.5 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments.

As of June 30, 2018, borrowings of $956 million were outstanding under the Parent Company revolving credit facility and the amount available for future borrowings was $544 million.

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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”) allows for unsecured borrowings up to $4.00 billion and matures in December 2022. 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 June 30, 2018, the ETP Five-Year Credit Facility had $1.23 billion outstanding, all of which was commercial paper. The amount available for future borrowings was $2.61 billion after taking into account letters of credit of $167 million. The weighted average interest rate on the total amount outstanding as of June 30, 2018 was 2.87%.

ETP 364-Day Facility

ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) allows for unsecured borrowings up to $1.0 billion and matures on November 30, 2018. As of June 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 June 30, 2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of June 30, 2018 was 3.72%.

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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, which matures in September 2019. As of June 30, 2018, the Sunoco LP credit facility had $320 million outstanding borrowings and $8 million in standby letters of credit. The unused availability on the revolver at June 30, 2018 was $1.2 billion.

In July 2018, Sunoco LP amended its revolving credit agreement, including extending the expiration to July 27, 2023 (which may be extended in accordance with the terms of the credit agreement).

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 June 30, 2018, USAC had $950 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of June 30, 2018, USAC had $650 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 June 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 June 30, 2018 include (i) a balance of $465 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 their preferred units by the fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the

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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 six months ended June 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 June 30, 2018	—		1,158.2

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 June 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 ETE common units in accordance with the terms of ETE’s partnership agreement.

Repurchase Program

During the six months ended June 30, 2018, ETE did not repurchase any ETE common units under its current buyback program. As of June 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 six months ended June 30, 2018, we recognized a decrease in partners’ capital of $125 million.

ETP Equity Distribution Program

During the six months ended June 30, 2018, there were no ETP common units issued under ETP’s equity distribution agreements. As of June 30, 2018, $752 million of ETP’s common units remained available to be issued under ETP’s existing $1.00 billion equity distribution agreement.

ETP Distribution Reinvestment Program

In July 2017, ETP initiated a new distribution reinvestment plan. During the six months ended June 30, 2018, distributions of $39 million were reinvested under ETP’s distribution reinvestment plan.

ETP Preferred Units

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

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.

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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.

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.

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USAC Distribution Reinvestment Program

During the three months ended June 30, 2018, distributions of $0.2 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 11,776 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

⁽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

ETP Cash Distributions

Distributions declared and/or paid by ETP subsequent to December 31, 2017 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

ETE has agreed to relinquish its right to the following amounts of incentive distributions from ETP in future periods:



	Year Ending December 31,
2018 (remainder)	$	69
2019	128
Each year beyond 2019	33

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Distributions on 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	0.563

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

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 June 30, 2018, USAC had 89,953,049 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

Accumulated Other Comprehensive Income

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



	June 30, 2018			December 31, 2017
Available-for-sale securities ⁽¹⁾	$	4		$	8
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(7		)	(5		)
Investments in unconsolidated affiliates, net	12			5
Subtotal	4			3
Amounts attributable to noncontrolling interest	(4		)	(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.

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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 six months ended June 30, 2018, the Partnership’s income tax benefit also reflected $13 million and $51 million, respectively, of deferred benefit adjustments as the result of a state statutory rate reduction.

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 audit is ongoing.

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.

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 June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Rental expense ⁽¹⁾	$	42		$	41		$	74		$	81
Less: Sublease rental income	(11		)	(6		)	(17		)	(12		)
Rental expense, net	$	31		$	35		$	57		$	69


⁽¹⁾	Includes contingent rentals totaling $1 million and $6 million for three months ended June 30, 2018 and 2017, respectively and $2 million and $10 million for the six months ended June 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 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 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

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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 Tribes 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 Tribe.

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. Following the completion of the remand process by the USACE, 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.

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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 June 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.

Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. On April 5, 2018, the Court entered an Order dismissing the matter with prejudice.

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.

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Litigation Filed By or Against Williams

On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ETE and LE GP, LLC (“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.

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

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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.

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.

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.

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, and July 18, 2018.

Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Defendants’ motions to dismiss are due on or before September 10, 2018.

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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 June 30, 2018 and December 31, 2017, accruals of approximately $58 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 West Whiteland 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 West Whiteland Township.

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

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Service on ME1 was resumed in accordance with PUC’s Opinion and Order. Senator Dinniman’s Complaint will proceed forward under a schedule to be determined by the ALJ. A prehearing conference with the ALJ is scheduled for August 28, 2018.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”). 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 June 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, 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 estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January 2015. In May 2017, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July 2017, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. Sin

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ce then, the parties have reached an agreement in principal to resolve all penalties. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality, and we are involved in settlement discussion with the agencies.

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 June 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.



	June 30, 2018		December 31, 2017
Current	$	51	$	35
Non-current	352		337
Total environmental liabilities	$	403	$	372

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

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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 June 30, 2018 and 2017, the Partnership recorded $9 million and $10 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2018 and 2017, the Partnership recorded $15 million and $18 million, respectively, of expenditures related to environmental cleanup programs.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, EPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

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

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 six months ended June 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

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•Investment in Sunoco LP


•	fuel distribution and marketing


•	all other

•Investment in USAC


•	contract operations


•	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 ETP’s 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 ETP’s 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 ETP’s pipelines or inject/withdraw into or out of ETP’s 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 ETP accepts 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 ETP’s 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 ETP’s storage facilities. ETP’s 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, ETP 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 ETP’s pipelines or inject into or withdrawn out of ETP’s storage facilities. Consequently, ETP is 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.

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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 services, but such promise is made on a case-by-case basis at the time the customer requests the service and ETP accepts the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.

ETP’s midstream revenue

ETP’s midstream revenues are derived primarily from margins ETP earns for natural gas volumes that are gathered, processed, and/or transported for ETP’s customers. The various types of revenue contracts ETP’s midstream operations enter into include:

Fixed fee gathering and processing: Contracts under which ETP provides 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 ETP gathers 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, ETP retains 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 ETP provides 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: ETP retains its POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. ETP recognizes revenue for the non-cash consideration and cash fees at the time the services are performed.

•

Mixed POP: ETP purchases NGLs from the producer and retains a portion of the residue gas as non-cash consideration for services provided. ETP 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 ETP purchased and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, ETP 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 ETP’s 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 ETP’s 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, ETP defers 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

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provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed.

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

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

ETP’s all other revenue

ETP’s other operations primarily include ETP’s 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. ETP also earns 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).

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 take-or-pay 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.

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.

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

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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.

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

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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 June 30, 2018, the Partnership had $271 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 June 30, 2018		Increase/ (Decrease)
Contract Balances
Contract Asset	$	51	$	59	$	8
Accounts receivable from contracts with customers	445		487		42
Contract Liability	1		1		—

The amount of revenue recognized for the three and six months ended June 30, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $28 million and $63 million, respectively.

Performance Obligations

At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contacts, only the fixed component of the contracts are included in the table below.

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 minimum volume of fuel 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

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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 June 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $41.9 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:



	2018 (remainder)		2019		2020		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of June 30, 2018	$	2,694	$	5,240	$	4,732	$	29,258	$	41,924

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 six months ended June 30, 2018 was $3 million and $6 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:



	June 30, 2018			December 31, 2017
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	465		2018	1,078		2018
Basis Swaps IFERC/NYMEX ⁽¹⁾	102,328		2018-2020	48,510		2018-2020
Options – Puts	(3,043	)	2018	13,000		2018
Power (Megawatt):
Forwards	3,196,100		2018-2019	435,960		2018-2019
Futures	(42,768	)	2018	(25,760	)	2018
Options — Puts	(30,532	)	2018	(153,600	)	2018
Options — Calls	996,172		2018	137,600		2018
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	6,600		2018-2020	4,650		2018-2020
Swing Swaps IFERC	52,413		2018-2019	87,253		2018-2019
Fixed Swaps/Futures	5,460		2018-2019	(4,390	)	2018-2019
Forward Physical Contracts	(174,465	)	2018-2020	(145,105	)	2018-2020
NGL (MBbls) – Forwards/Swaps	(1,590	)	2018-2019	(2,493	)	2018-2019
Crude (MBbls) – Forwards/Swaps	44,335		2018-2019	9,237		2018-2019
Refined Products (MBbls) – Futures	(776	)	2018-2021	(3,901	)	2018-2019
Corn (thousand bushels)	(3,320	)	2018-2019	1,870		2018
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	2018	(39,770	)	2018
Fixed Swaps/Futures	(21,475	)	2018	(39,770	)	2018
Hedged Item — Inventory	21,475		2018	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⁾	June 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 ETP’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, ETP may at times require collateral under certain circumstances to mitigate credit risk as necessary. ETP 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, ETP utilizes master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

ETP’s 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. ETP’s 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.

ETP has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about the settlement date for non-exchange traded derivatives, and ETP exchanges 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
	June 30, 2018		December 31, 2017		June 30, 2018			December 31, 2017
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	14	$	(2	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	307		262		(352		)	(281		)
Commodity derivatives	112		45		(430		)	(58		)
Interest rate derivatives	—		—		(147		)	(219		)
	419		307		(929		)	(558		)
Total derivatives	$	419	$	321	$	(931	)	$	(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	June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(147	)	$	(219	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	112			45			(430		)	(58		)
Broker cleared derivative contracts	Other current assets (liabilities)	307			276			(354		)	(283		)
Total gross derivatives		419			321			(931		)	(560		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(49		)	(21		)	49			21
Counterparty netting	Other current assets (liabilities)	(306		)	(263		)	306			263
Total net derivatives		$	64		$	37		$	(576	)	$	(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/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2018		2017		2018		2017
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	6	$	6	$	9	$	2



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2018			2017			2018			2017
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	16		$	15		$	33		$	26
Commodity derivatives — Non-trading	Cost of products sold	(295		)	17			(366		)	19
Interest rate derivatives	Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Embedded derivatives	Other, net	—			—			—			1
Total		$	(259	)	$	7		$	(261	)	$	26

14. RELATED PARTY TRANSACTIONS

Revenues reported in ETE’s consolidated statements of operations included sales with affiliates of $120 million and $46 million during the three months ended June 30, 2018 and 2017, respectively, and $222 million and $96 million during the six months ended June 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.

The following tables present financial information by segment:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Investment in ETP	$	2,051		$	1,545		$	3,932		$	2,990
Investment in Sunoco LP	140			220			249			375
Investment in USAC	95			—			95			—
Investment in Lake Charles LNG	45			44			88			88
Corporate and Other	(9		)	(9		)	(8		)	(22		)
Adjustments and Eliminations	(60		)	(83		)	(92		)	(137		)
Total	2,262			1,717			4,264			3,294
Depreciation, depletion and amortization	(694		)	(607		)	(1,359		)	(1,235		)
Interest expense, net of interest capitalized	(510		)	(477		)	(976		)	(950		)
Impairment losses	—			(89		)	—			(89		)
Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Non-cash compensation expense	(32		)	(20		)	(55		)	(47		)
Unrealized gains (losses) on commodity risk management activities	(265		)	29			(352		)	98
Losses on extinguishments of debt	—			—			(106		)	(25		)
Inventory valuation adjustments	32			(29		)	57			(42		)
Equity in earnings of unconsolidated affiliates	92			49			171			136
Adjusted EBITDA related to unconsolidated affiliates	(168		)	(164		)	(324		)	(349		)
Adjusted EBITDA related to discontinued operations	5			(72		)	25			(103		)
Other, net	(15		)	35			26			47
Income from continuing operations before income tax expense	727			347			1,443			715
Income tax expense from continuing operations	(68		)	(33		)	(58		)	(71		)
Income from continuing operations	659			314			1,385			644
Loss from discontinued operations, net of income taxes	(26		)	(193		)	(263		)	(204		)
Net income	$	633		$	121		$	1,122		$	440

* As adjusted. See Note 1.

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	June 30, 2018			December 31, 2017
Assets:
Investment in ETP	$	78,570		$	77,965
Investment in Sunoco LP	5,006			8,344
Investment in USAC	3,785			—
Investment in Lake Charles LNG	1,710			1,646
Corporate and Other	585			598
Adjustments and Eliminations	(2,239		)	(2,307		)
Total assets	$	87,417		$	86,246



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Revenues:
Investment in ETP:
Revenues from external customers	$	9,298		$	6,485		$	17,383		$	13,292
Intersegment revenues	112			91			307			179
	9,410			6,576			17,690			13,471
Investment in Sunoco LP:
Revenues from external customers	4,606			2,892			8,354			5,697
Intersegment revenues	1			—			2			3
	4,607			2,892			8,356			5,700
Investment in USAC:
Revenues from external customers	165			—			165			—
Intersegment revenues	2			—			2			—
	167			—			167			—
Investment in Lake Charles LNG:
Revenues from external customers	49			50			98			99

Adjustments and Eliminations	(115		)	(91		)	(311		)	(182		)
Total revenues	$	14,118		$	9,427		$	26,000		$	19,088

* As adjusted. See Note 1.

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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 June 30,				Six Months Ended June 30,
	2018		2017*		2018		2017*
Intrastate transportation and storage	$	761	$	699	$	1,578	$	1,467
Interstate transportation and storage	323		201		636		432
Midstream	594		633		1,034		1,198
NGL and refined products transportation and services	2,472		1,767		4,930		3,885
Crude oil transportation and services	4,789		2,460		8,520		5,035
All Other	471		816		992		1,454
Total revenues	9,410		6,576		17,690		13,471
Less: Intersegment revenues	112		91		307		179
Revenues from external customers	$	9,298	$	6,485	$	17,383	$	13,292

* 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.

Investment in Sunoco LP



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Fuel distribution and marketing	$	4,350	$	2,318	$	7,489	$	4,615
All other	257		574		867		1,085
Total revenues	4,607		2,892		8,356		5,700
Less: Intersegment revenues	1		—		2		3
Revenues from external customers	$	4,606	$	2,892	$	8,354	$	5,697

Investment in USAC



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Contract operations	$	160	$	—	$	160	$	—
Retail parts and services	6		—		6		—
Station installations revenue	1		—		1		—
Total revenues	167		—		167		—
Less: Intersegment revenues	2		—		2		—
Revenues from external customers	$	165	$	—	$	165	$	—

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)



	June 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	1
Accounts receivable from related companies	58			65
Other current assets	—			1
Total current assets	59			67
Property, plant and equipment, net	27			27
Advances to and investments in unconsolidated affiliates	6,042			6,082
Goodwill	9			9
Other non-current assets, net	7			8
Total assets	$	6,144		$	6,193
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities:
Interest payable	$	70		$	66
Accrued and other current liabilities	8			4
Total current liabilities	78			70
Long-term debt, less current maturities	6,472			6,700
Long-term notes payable – related companies	702			617
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ deficit:
Limited Partners:
Series A Convertible Preferred Units	—			450
Common Unitholders	(1,106		)	(1,643		)
General Partner	(4		)	(3		)
Total partners’ deficit	(1,110		)	(1,196		)
Total liabilities and partners’ deficit	$	6,144		$	6,193

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(9	)	$	(9	)	$	(11	)	$	(22	)
OTHER INCOME (EXPENSE):
Interest expense, net	(90		)	(86		)	(176		)	(169		)
Equity in earnings of unconsolidated affiliates	454			308			902			669
Losses on extinguishments of debt	—			—			—			(25		)
Other, net	—			(1		)	3			(2		)
NET INCOME	355			212			718			451
Convertible Unitholders’ interest in income	12			8			33			14
General Partner’s interest in net income	1			—			2			1
Limited Partners’ interest in net income	$	342		$	204		$	683		$	436

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STATEMENTS OF CASH FLOWS

(unaudited)



	Six Months Ended June 30,
	2018			2017
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	626		$	405
CASH FLOWS FROM INVESTING ACTIVITIES
Contributions to unconsolidated affiliate	(250		)	(861		)
Capital expenditures	—			(1		)
Contributions in aid of construction costs	—			6
Sunoco LP Series A Preferred Units redemption	303			—
Net cash provided by (used in) investing activities	53			(856		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	355			2,072
Principal payments on debt	(587		)	(1,740		)
Proceeds from affiliate	85			87
Distributions to partners	(532		)	(501		)
Units issued for cash	—			568
Debt issuance costs	—			(35		)
Net cash provided by (used in) financing activities	(679		)	451
CHANGE IN CASH AND CASH EQUIVALENTS	—			—
CASH AND CASH EQUIVALENTS, beginning of period	1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	2

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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 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 Equity, L.P. on a stand-alone basis.

OVERVIEW

At June 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 owns 100 ETP Class I Units, which are currently 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

ETE Series A Convertible Preferred Units

ETP Series D Preferred Units Issuance

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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 late fourth quarter of 2018.

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.

New Ethane Export Facility Joint Venture

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

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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 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 July 2018, ETE announced its quarterly distribution of $0.305 per unit ($1.22 annualized) on ETE common units for the quarter ended June 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

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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 the 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 are 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. 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 NOI or as contemplated in the Final Rule, the FERC or our shippers may challenge the cost of service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP, 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.

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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 the 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 June 30,									Six Months Ended June 30,
	2018			2017*			Change			2018			2017*			Change
Segment Adjusted EBITDA:
Investment in ETP	$	2,051		$	1,545		$	506		$	3,932		$	2,990		$	942
Investment in Sunoco LP	140			220			(80		)	249			375			(126		)
Investment in USAC	95			—			95			95			—			95
Investment in Lake Charles LNG	45			44			1			88			88			—
Corporate and Other	(9		)	(9		)	—			(8		)	(22		)	14
Adjustments and Eliminations	(60		)	(83		)	23			(92		)	(137		)	45
Total	2,262			1,717			545			4,264			3,294			970
Depreciation, depletion and amortization	(694		)	(607		)	(87		)	(1,359		)	(1,235		)	(124		)
Interest expense, net of interest capitalized	(510		)	(477		)	(33		)	(976		)	(950		)	(26		)
Impairment losses	—			(89		)	89			—			(89		)	89
Gains (losses) on interest rate derivatives	20			(25		)	45			72			(20		)	92
Non-cash compensation expense	(32		)	(20		)	(12		)	(55		)	(47		)	(8		)
Unrealized gains (losses) on commodity risk management activities	(265		)	29			(294		)	(352		)	98			(450		)
Losses on extinguishments of debt	—			—			—			(106		)	(25		)	(81		)
Inventory valuation adjustments	32			(29		)	61			57			(42		)	99
Equity in earnings of unconsolidated affiliates	92			49			43			171			136			35
Adjusted EBITDA related to unconsolidated affiliates	(168		)	(164		)	(4		)	(324		)	(349		)	25
Adjusted EBITDA related to discontinued operations	5			(72		)	77			25			(103		)	128
Other, net	(15		)	35			(50		)	26			47			(21		)
Income from continuing operations before income tax benefit expense	727			347			380			1,443			715			728
Income tax expense from continuing operations	(68		)	(33		)	(35		)	(58		)	(71		)	13
Income from continuing operations	659			314			345			1,385			644			741
Loss from discontinued operations, net of income taxes	(26		)	(193		)	167			(263		)	(204		)	(59		)
Net income	$	633		$	121		$	512		$	1,122		$	440		$	682

* 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 six months ended June 30, 2018 compared to the same period last year increased primarily due to additional depreciation and amortization from assets recently placed in service.

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


•	increases of $22 million and $36 million, respectively, of expense recognized by ETP compared to the same periods in the prior year primarily attributable to increases in long-term debt; and

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•	increases of $4 million and $7 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 $26 million for both periods, due to the consolidation of USAC beginning April 2, 2018; partially offset by


•	decreases of $18 million and $42 million, respectively, of expense recognized by Sunoco LP compared to the same periods in the prior year primarily due to Sunoco LP’s repayment 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 six months ended June 30, 2018 and June 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 six months ended June 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. For the three months ended June 30, 2018 compared to the same period last year, the Partnership’s income tax expense increased primarily due to higher pretax income from our corporate subsidiaries. For the six months ended June 30, 2018 compared to the same period last year, the Partnership’s income tax expense decreased primarily due to a deferred benefit adjustment as the result of a state statutory rate reduction.

Segment Operating Results

Investment in ETP



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017*			Change			2018			2017*			Change
Revenues	$	9,410		$	6,576		$	2,834		$	17,690		$	13,471		$	4,219
Cost of products sold	7,140			4,624			2,516			13,128			9,674			3,454
Unrealized (gains) losses on commodity risk management activities	265			(34		)	299			352			(98		)	450
Operating expenses, excluding non-cash compensation expense	(615		)	(532		)	(83		)	(1,202		)	(1,017		)	(185		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(99		)	(107		)	8			(199		)	(207		)	8
Adjusted EBITDA related to unconsolidated affiliates	228			247			(19		)	413			486			(73		)
Other, net	2			19			(17		)	6			29			(23		)
Segment Adjusted EBITDA	$	2,051		$	1,545		$	506		$	3,932		$	2,990		$	942

* As adjusted.

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Segment Adjusted EBITDA. For the three months ended June 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 $60 million in ETP’s intrastate transportation and storage operations resulting from an increase of $47 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity; a net increase of $5 million due to the consolidation of RIGS beginning in April 2018; an increase of $4 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, due to higher demand on existing pipelines; and an increase of $3 million in realized storage margin primarily due to higher realized derivative gains;

•

an increase of $68 million in ETP’s interstate transportation and storage operations due to an increase of $68 million due to the partial in service of the Rover pipeline with increases of $105 million in revenues, $30 million in operating expenses and $7 million in general and administrative expenses; and an increase of $19 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 $8 million in operating expenses, excluding the incremental expenses from Rover pipeline; an increase of $3 million in selling, general and administrative expenses, excluding the incremental expenses from Rover pipeline; and decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to lower sales of short-term firm capacity on Citrus;

•

an increase of $2 million in ETP’s midstream operations primarily due to an $8 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 $17 million increase in fee-based revenues due to increased volumes in the Permian and Northeast regions offset by declines in South Texas, North Texas and the midcontinent/Panhandle regions; and an increase of $2 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 $17 million in operating expenses primarily due to outside services and materials expense; and an increase of $9 million in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters;

•

an increase of $73 million in ETP’s NGL and refined products transportation and services operations due to an increase of $49 million in transportation volume, primarily due to a $43 million increase from higher volumes on ETP’s Texas NGL pipelines, an increase of $11 million resulting from reclassification between transportation and fractionation margins, and an increase of $4 million due to higher volumes on the Mariner West and Mariner South systems, offset by decrease of $11 million due to lower throughput on Mariner East 1 due to system downtime in the second quarter of 2018; an increase of $23 million in marketing margin (excluding a net change of $17 million in unrealized gains and losses) due to gains of $10 million from ETP’s butane blending operations, an increase of $9 million from sales of domestic propane from other products at ETP’s Marcus Hook Industrial Complex and an increase of $4 million from optimizing sales of purity projects from ETP’s Mont Belvieu fractionators; an increase of $11 million in fractionation and refinery services margin, due to a $14 million increase resulting from higher NGL volumes from the Permian region feeding ETP’s Mont Belvieu fractionation facility and a $6 million increase from blending gains as a result of improved market pricing, offset by a decrease of $11 million resulting from reclassification between ETP’s transportation and fraction margins; and an increase of $10 million in terminalling services margin primarily 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; partially offset by an increase of $16 million in operating expenses and a decrease of $5 million in storage margin primarily due to the expiration and amendments to various NGL and refined products storage contracts;

•

an increase of $320 million in ETP’s crude oil transportation and services operations primarily due to an increase of $193 million resulting primarily from placing ETP’s Bakken pipeline in service in the second quarter of 2017 as well as a $27 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets, a $100 million increase (excluding a net change of $264 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 $9 million increase in terminal fees primarily from ship loading fees at ETP’s Nederland facility as a result of increased exports; a decrease of $12 million in selling, general and administrative expense primarily due to higher professional fees recorded in the prior period; and an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of ETP’s joint ventures; partially offset by an increase of $30 million in operating expenses primarily due to assets recently placed in service, as well as higher expenses on existing assets; partially offset by

•

a decrease of $17 million in ETP’s all other operations due to a decrease of $44 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; and a decrease of $12 million due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method

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investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by a decrease of $14 million in merger and acquisition expense related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018; an increase of $12 million in Adjusted EBITDA related to unconsolidated affiliates from ETP’s investment in PES; an increase of $6 million from gains in power trading activities; and an increase of $2 million in margin due to the expiration of a capacity contract commitment.

Segment Adjusted EBITDA. For the six months ended June 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 $83 million in ETP’s intrastate transportation and storage operations resulting from an increase of $105 million in realized natural gas sales and other margin due to higher realized gains from pipeline optimization activity; and a net increase of $5 million due to the consolidation of RIGS beginning in April 2018; partially offset by a decrease of $21 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory; a decrease of $3 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to renegotiated contracts; and a decrease of $2 million in retained fuel revenues due to lower natural gas pricing.

•

an increase of $126 million in ETP’s interstate transportation and storage operations due to an increase of $117 million due to the partial in service of the Rover pipeline in August 2017 with increases of $187 million in revenues, $56 million in operating expenses and $14 million in general and administrative expenses; and an increase of $21 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 $6 million of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by increase of $2 million in operating expenses, excluding the incremental expenses from Rover pipeline; and a decrease of $4 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short term firm capacity on Citrus;

•

an increase of $59 million in ETP’s midstream operations primarily due to a $51 million increase in non-fee-based margins due to higher realized crude oil and NGL prices and increased throughput in the Permian region; a $30 million increase in gathering and fee-based revenues due to increased volumes in the Permian and Northeast regions offset by declines in South Texas, North Texas and the midcontinent/Panhandle regions; and an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by an increase of $20 million in operating expenses primarily due to outside services and materials expense; and an increase of $6 million in selling, general and administrative expenses primarily due to a favorable impact recorded in the prior period from the adjustment of certain reserves in connection with contingent matters;

•

an increase of $143 million in ETP’s NGL and refined products transportation and services operations due to an increase of $82 million in transportation volume, primarily due to $78 million increase from higher volumes on ETP’s Texas NGL pipelines, an increase of $11 million resulting from reclassification between transportation and fractionation margins and $14 million from higher volumes on the Mariner West and Mariner South systems, partially offset by a $17 million decrease resulting from lower throughput on Mariner East 1 due to system downtime in 2018 and $8 million due to lower transport revenue from the Eagle Ford and Southeast Texas regions; an increase of $48 million in marketing margin (excluding a net change of $54 million in unrealized gains and losses) due to an $18 million increase from ETP’s butane blending operations, a $17 million increase from sales of domestic propane from other products at ETP’s Marcus Hook Industrial Complex and a $13 million increase from optimizing sales of purity products from ETP’s Mont Belvieu fractionators; and an increase of $25 million in fractionation and refinery services margin, due to a $23 million increase resulting from higher NGL volumes from the Permian region feeding ETP’s Mont Belvieu fractionation facility and a $9 million increase from blending gains as a result of improved market pricing, offset by a decrease of $11 million resulting from reclassification between ETP’s transportation and fraction margins; an increase of $17 million in terminalling services margin primarily 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; and an increase of $5 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 $28 million in operating expenses and a decrease in storage margin due to a $8 million decrease from the expiration and amendments to various NGL and refined products storage contracts

•

an increase of $597 million in ETP’s crude oil transportation and services operations primarily due to a $417 million increase resulting primarily from placing ETP’s Bakken pipeline in service in the second quarter of 2017, a $50 million increase resulting from increased throughput, primarily from Permian producers, on existing pipeline assets, a $188 million increase (excluding a net change of $307 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 $16 million increase primarily from ETP’s Nederland facility due to higher ship loading fees as a result of increased exports; a decrease of $7 million in selling, general and administrative expenses primarily due to a decrease in professional

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fees; and an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of ETP’s joint ventures; partially offset by an increase of $85 million in operating expenses primarily due to assets recently placed in service, as well as higher expenses on existing assets; partially offset by

•

a decrease of $66 million in ETP’s all other operations due to a decrease of $69 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 $18 million in Adjusted EBITDA related to unconsolidated affiliates primarily from our investment in PES; a decrease of $9 million due to the contribution of CDM to USAC in April 2018, which decrease reflects the impact of deconsolidating CDM, partially offset by an increase in Adjusted EBITDA related to unconsolidated affiliates due to the equity method investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by a decrease of $17 million in merger and acquisition expenses related to the Sunoco Logistics merger in 2017, partially offset by the CDM Contribution in 2018; an increase of $8 million from commodity trading activities; and an increase of $5 million in margin from the expiration of a capacity contract commitment.

Investment in Sunoco LP



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Revenues	$	4,607		$	2,892		$	1,715		$	8,356		$	5,700		$	2,656
Cost of products sold	4,297			2,633			1,664			7,750			5,185			2,565
Unrealized gains on commodity risk management activities	—			5			(5		)	—			—			—
Operating expenses, excluding non-cash compensation expense	(105		)	(115		)	10			(218		)	(227		)	9
Selling, general and administrative, excluding non-cash compensation expense	(31		)	(31		)	—			(63		)	(59		)	(4		)
Inventory fair value adjustments	(32		)	30			(62		)	(57		)	43			(100		)
Adjusted EBITDA from discontinued operations	(5		)	72			(77		)	(25		)	103			(128		)
Other	3			—			3			6			—			6
Segment Adjusted EBITDA	$	140		$	220		$	(80	)	$	249		$	375		$	(126	)

Segment Adjusted EBITDA. For the three months ended June 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 $77 million in Adjusted EBITDA from discontinued operations primarily attributable to Sunoco LP’s retail divestment in January 2018; offset by


•	a decrease in other operating expense of $10 million primarily due to a decrease in rent expense of $3 million and a decrease in other operating of $7 million primarily due to lower salaries and benefits; and

•

an increase in fuel distribution and marketing gross profit on motor fuel of a $102 million primarily due to a $62 million favorable change in inventory adjustments, as well as an increase in motor fuel gallons sold, partially offset by a decrease in gross profit of $51 million from other motor fuel, merchandise, rental and other due to the conversion of 207 retail sites to commission agent sites during the current period.

Segment Adjusted EBITDA. For the six months ended June 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 $128 million in Adjusted EBITDA from discontinued operations primarily attributable to Sunoco LP’s retail divestment in January 2018; offset by

•

an increase in fuel distribution and marketing gross profits on motor fuel of $140 million primarily due to $100 million favorable change in inventory adjustments, as well as an increase in motor fuel gallons sold, partially offset by a decrease in gross profit of $49 million from other motor fuel, merchandise, rental and other due to the conversion of 207 retail sites to commission agent sites during the current period; and

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•	a decrease in other operating expense of $9 million primarily due to a net decrease in rent expense of $8 million.

Investment in USAC



	Three Months Ended June 30,								Six Months Ended June 30,
	2018			2017		Change			2018			2017		Change
Revenues	$	167		$	—	$	167		$	167		$	—	$	167
Cost of products sold	20			—		20			20			—		20
Operating expenses, excluding non-cash compensation expense	(38		)	—		(38		)	(38		)	—		(38		)
Selling, general and administrative, excluding non-cash compensation expense	(19		)	—		(19		)	(19		)	—		(19		)
Other	5			—		5			5			—		5
Segment Adjusted EBITDA	$	95		$	—	$	95		$	95		$	—	$	95

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

Investment in Lake Charles LNG



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Revenues	$	49		$	50		$	(1	)	$	98		$	99		$	(1	)
Operating expenses, excluding non-cash compensation expense	(4		)	(4		)	—			(9		)	(9		)	—
Selling, general and administrative, excluding non-cash compensation expense	—			(2		)	2			(1		)	(2		)	1
Segment Adjusted EBITDA	$	45		$	44		$	1		$	88		$	88		$	—

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 the limited partner and general partner interests in ETP, Sunoco LP and USAC and cash flows from the operations of 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. In connection with previous transactions, we have relinquished a portion of our incentive distributions to be received from ETP and Sunoco LP, see additional discussion under “Cash Distributions.”

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⁾	500		550		115		120
Midstream	850		875		120		130
NGL and refined products transportation and services	2,350		2,500		60		70
Crude oil transportation and services ⁽¹⁾	450		475		90		100
All other (including eliminations)	75		100		60		65
Total capital expenditures	$	4,500	$	4,800	$	475	$	520


⁽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 months ended June 30, 2018 was $15 million. USAC currently

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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 $210 million in expansion capital expenditures during 2018. USAC’s expansion capital expenditures for the three months ended June 30, 2018 was $44 million. As of June 30, 2018, USAC has binding commitments to purchase $122 million of additional compression units and serialized parts, of which USAC expects to spend $72 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.

Six months ended June 30, 2018 compared to six months ended June 30, 2017. Cash provided by operating activities during 2018 was $3.16 billion as compared to $1.46 billion for 2017. Net income was $1.12 billion and $440 million for 2018 and 2017, respectively. The difference between net income and the net cash provided by operating activities for the six months ended June 30, 2018 and 2017, primarily consisted of non-cash items totaling $1.31 billion and $1.21 billion, respectively, and net changes in operating assets and liabilities of $357 million and $582 million, respectively.

The non-cash activity in 2018 and 2017 consisted primarily of depreciation, depletion and amortization of $1.36 billion and $1.24 billion, respectively, equity in earnings of unconsolidated affiliates of $171 million and $136 million, respectively, inventory valuation adjustments of $57 million and $42 million, respectively, deferred income tax expense of $71 million and $59 million, respectively, losses on extinguishments of debt of $106 million and $25 million, respectively, and non-cash compensation expense of $55 million and $47 million, respectively.

Cash paid for interest, net of interest capitalized, was $919 million and $960 million for the six months ended June 30, 2018 and 2017, respectively.

Capitalized interest was $161 million and $130 million for the six months ended June 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.

Six months ended June 30, 2018 compared to six months ended June 30, 2017. Cash used in investing activities during 2018 was $3.14 billion as compared to cash used in investing activities $1.54 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 $3.48 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 $2.86 billion. In 2018 and 2017, we paid net cash for acquisitions of $143 million and $569 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 $2.0 billion.

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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.

Six months ended June 30, 2018 compared to six months ended June 30, 2017. Cash used in financing activities during 2018 was $2.58 billion as compared to cash used in financing activities of $81 million for 2017. In 2018, ETE received $954 million in net proceeds from offerings of subsidiary common units and warrants as compared to $1.03 billion in 2017. During 2018, we had a consolidated net decrease in our debt level of $1.34 billion as compared to a net increase of $646 million for 2017. In 2017, we paid net proceeds on affiliates notes in the amount of $255 million. We have paid distributions of $532 million and $501 million to our partners in 2018 and in 2017, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $1.79 billion and $1.40 billion in 2018 and 2017, respectively. We paid $173 million and $35 million in debt issuance costs in 2018 and 2017, respectively. In addition, we have received capital contributions of $318 million in cash from noncontrolling interests in 2018 compared to $456 million in 2017.

Discontinued Operations

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

Six months ended June 30, 2018 compared to six months ended June 30, 2017

Cash provided by discontinued operations during 2018 was $2.74 billion, resulting from cash used in operating activities of $478 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 $67 million, resulting from cash provided by operating activities of $131 million, cash used in investing activities of $62 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:



	June 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	956			1,188
Subsidiary Indebtedness:
ETP Senior Notes ⁽¹⁾⁽²⁾	29,354			27,005
Transwestern Senior Notes	575			575
Panhandle Senior Notes	386			785
Sunoco LP Senior Notes, Term Loan and lease-related obligation	2,312			3,556
USAC Senior Notes	725			—
Credit Facilities and Commercial Paper:
ETP $4.0 billion Revolving Credit Facility due December 2022 ⁽³⁾	1,228			2,292
ETP $1.0 billion 364-Day Credit Facility due November 2018	—			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	320			765
USAC $1.6 billion Revolving Credit Facility due April 2023	950			—
Other Long-Term Debt	6			8
Unamortized premiums and fair value adjustments, net	28			50
Deferred debt issuance costs	(264		)	(247		)
Total	44,633			44,084
Less: Current maturities of long-term debt	160			413
Long-term debt and notes payable, less current maturities	$	44,473		$	43,671


⁽¹⁾	Includes $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018 that were classified as long-term as of June 30, 2018 as they were refinanced on a long-term basis.


⁽²⁾	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 June 30, 2018 as management has the intent and ability to refinance the borrowings on a long-term basis.


⁽³⁾	Includes $1.23 billion and $2.01 billion of commercial paper outstanding at June 30, 2018 and December 31, 2017, respectively.

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

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

USAC Senior Notes

ETE Revolving Credit Facility

As of June 30, 2018, borrowings of $956 million were outstanding under the Parent Company revolving credit facility and the amount available for future borrowings was $544 million.

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

ETP’s revolving credit facility (the “ETP Five-Year Credit Facility”) allows for unsecured borrowings up to $4.0 billion and matures in December 2022. The ETP Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.0 billion under certain conditions.

ETP 364-Day Facility

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Bakken Credit Facility

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement which matures in September 2019. As of June 30, 2018, the Sunoco LP credit facility had $320 million outstanding borrowings and $8 million in standby letters of credit. The unused availability on the revolver at June 30, 2018 was $1.2 billion.

In July 2018, Sunoco LP amended its revolving credit agreement, including extending the expiration to July 27, 2023 (which may be extended in accordance with the terms of the credit agreement).

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.

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 June 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

⁽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):



	Six Months Ended June 30,
	2018		2017
Limited Partners	$	618	$	500
General Partner interest	2		2
Total Parent Company distributions	$	620	$	502

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 contributes 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:



	Six Months Ended June 30,
	2018			2017
Distributions from ETP:
Limited Partner interests	$	31		$	30
General partner interest and IDRs	900			781
IDR relinquishments net of Class I Unit distributions	(84		)	(319		)
Total distributions from ETP	847			492
Distributions from Sunoco LP
Limited Partner interests	4			4
IDRs	35			42
Series A Preferred	—			8
Total distributions from Sunoco LP	39			54
Distributions from USAC
Limited Partner interests	11			—
Total distributions from USAC	11			—
Total distributions received from subsidiaries	$	897		$	546

ETE has agreed to relinquish its right to the following amounts of incentive distributions from the ETP in future periods:



	Year Ending December 31,
2018 (remainder)	$	69
2019	128
Each year beyond 2019	33

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ETE may agree to relinquish its rights to additional amounts of incentive distributions from ETP or Sunoco LP in future periods without the consent of ETE unitholders.

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.

Cash Distributions Paid by ETP

Distributions declared and/or paid by ETP subsequent to December 31, 2017 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	0.56337

The total amount of distributions declared during the periods presented were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):



	Six Months Ended June 30,
	2018			2017
Limited Partners:
Common Units held by public	$	1,286		$	1,156
Common Units held by ETE	31			30
General Partner interest and incentive distributions held by ETE	900			781
IDR relinquishments	(84		)	(319		)
ETP Series A Preferred Units	30			—
ETP Series B Preferred Units	18			—
ETP Series C Preferred Units	10			—
Total distributions declared to partners	$	2,191		$	1,648

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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

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):



	Six Months Ended June 30,
	2018		2017
Limited Partners:
Common units held by public	$	89	$	89
Common and subordinated units held by ETP	43		100
Common and subordinated units held by ETE	4		4
General Partner interest and incentive distributions	35		42
Series A Preferred	—		8
Total distributions declared	$	171	$	243

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

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):



	Six Months Ended June 30,
	2018
Limited Partners:
Common units held by public and other	$	63
Common units held by ETP	20
Common held by ETE	11
Total distributions declared	$	94

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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.



	June 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	465		$	—		$	—	1,078		$	—		$	—
Basis Swaps IFERC/NYMEX ⁽¹⁾	102,328		4			—		48,510		2			1
Options – Puts	(3,043	)	—			—		13,000		—			—
Options – Calls	—		—			—		—		—			—
Power (Megawatt):
Forwards	3,196,100		12			8		435,960		1			1
Futures	(42,768	)	—			—		(25,760	)	—			—
Options — Puts	(30,532	)	1			—		(153,600	)	—			1
Options — Calls	996,172		—			1		137,600		—			—
Crude (MBbls) – Futures	—		—			—		—		1			—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	6,600		(51		)	18		4,650		(13		)	4
Swing Swaps IFERC	52,413		(1		)	—		87,253		(2		)	1
Fixed Swaps/Futures	5,460		(2		)	3		(4,390	)	(1		)	2
Forward Physical Contracts	(174,465	)	4			—		(145,105	)	6			41
NGL (MBbls) – Forwards/Swaps	(1,590	)	(18		)	11		(2,493	)	5			16
Crude (MBbls) – Forwards/Swaps	44,335		(307		)	261		9,237		(4		)	9
Refined Products (MBbls) – Futures	(776	)	(6		)	6		(3,901	)	(27		)	4
Corn (thousand bushels)	(3,320	)	1			—		1,870		—			—
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(21,475	)	(1		)	—		(39,770	)	(2		)	—
Fixed Swaps/Futures	(21,475	)	(1		)	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 June 30, 2018, we and our subsidiaries had $7.78 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $78 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⁾	June 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 $254 million as of June 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 $8 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 President (“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 June 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 have begun the evaluation of the internal control structure of USAC. We expect that evaluation to continue during the remainder of 2018. In recording the USAC Transaction, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of USAC from the date of the USAC Transaction that are included in our results of operations for the three months ended June 30, 2018. None

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of the changes resulting from the USAC Transaction were in response to any 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 June 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 June 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.

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 $145,250 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. Further, on July 2, 2018, Luminant filed a request for immediate interim relief requesting that the TRRC issue an interim order requiring ETF to continue providing the same bundled transportation and storage service to Luminant that was being provided at the time Luminant filed both its formal and informal complaint. On July 3, 2018, ETF filed a response, opposing Luminant’s motion. On July 3, 2018, the TRRC issued an interim order denying temporary emergency relief. ETF filed a response to Luminant’s informal complaint on July 16, 2018. ETF’s response to Luminant’s formal complaint and a Motion to Dismiss were filed on July 23, 2018. A prehearing conference in this matter was scheduled for August 2, 2018 in Austin.

ETC Field Services LLC received NOV REG-0569-1801 on February 13, 2018 for emission events that occurred September 25, 2017 through December 29, 2017 at the Jal 3 gas plant. On June, 11, 2018, the New Mexico Environmental Department sent ETP a settlement offer to resolve the NOV for a penalty of $268,212. Negotiations for this settlement offer are ongoing.

ITEM 1A. RISK FACTORS

Set forth below are updated risk factors to reflect the Partnership’s consolidation of USAC and the merger of ETE and ETP. Except as set forth below, 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” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 filed with the SEC on May 10, 2018.

Risks Inherent in an Investment in Us

Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.

The Parent company’s principal source of earnings and cash flow is cash distributions from ETP, Sunoco LP and USAC. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP, Sunoco LP and USAC make to their partners. ETP, Sunoco LP and USAC may not be able to continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP, Sunoco LP or USAC increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP, Sunoco LP or USAC to us.

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Our ability to distribute cash received from ETP, Sunoco LP and USAC to our Unitholders is limited by a number of factors, including:


•	interest expense and principal payments on our indebtedness;


•	restrictions on distributions contained in any current or future debt agreements;


•	our general and administrative expenses;


•	expenses of our subsidiaries other than ETP, Sunoco LP and USAC, including tax liabilities of our corporate subsidiaries, if any; and


•	reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our General Partner.

Our cash flow depends primarily on the cash distributions we receive from our partnership interests in ETP, Sunoco LP and USAC, including the incentive distribution rights in ETP and Sunoco LP and, therefore, our cash flow is dependent upon the ability of ETP, Sunoco LP and USAC to make distributions in respect of those partnership interests.

We do not have any significant assets other than our partnership interests in ETP, Sunoco LP and USAC and our LNG business. As a result, our cash flow depends on the performance of ETP, Sunoco LP and USAC and their respective subsidiaries and ETP’s, Sunoco LP’s and USAC’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP, Sunoco LP and USAC.

The amount of cash that ETP, Sunoco LP and USAC can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend upon, among other things:


•	the amount of natural gas, NGLs, crude oil and refined products transported through ETP’s pipelines and gathering systems;


•	the level of throughput in processing and treating operations;


•	the fees charged and the margins realized by ETP, Sunoco LP and USAC for their services;


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


•	the relationship between natural gas, NGL and crude oil prices;


•	the amount of cash distributions ETP receives with respect to the Sunoco LP common units and USAC common units that ETP or its subsidiaries own;


•	the weather in their respective operating areas;


•	the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;


•	the level of their respective operating costs and maintenance and integrity capital expenditures;


•	the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;


•	prevailing economic conditions; and


•	the level and results of their respective derivative activities.

In addition, the actual amount of cash that ETP, Sunoco LP and USAC will have available for distribution will also depend on other factors, such as:


•	the level of capital expenditures they make;


•	the level of costs related to litigation and regulatory compliance matters;

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•	the cost of acquisitions, if any;


•	the levels of any margin calls that result from changes in commodity prices;


•	debt service requirements;


•	fluctuations in working capital needs;


•	their ability to borrow under their respective revolving credit facilities;


•	their ability to access capital markets;


•	restrictions on distributions contained in their respective debt agreements; and


•	the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.

ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors and ETP’s General Partners. Accordingly, we cannot guarantee that ETP, Sunoco LP and USAC will have sufficient available cash to pay a specific level of cash distributions to its partners.

Furthermore, Unitholders should be aware that the amount of cash that ETP, Sunoco LP and USAC have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP, Sunoco LP and USAC may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of our Subsidiaries” included in this Item 1A for a discussion of further risks affecting ETP’s, Sunoco LP’s and USAC’s ability to generate distributable cash flow.

ETP, Sunoco LP and USAC may issue additional Common Units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.

The partnership agreements of ETP, Sunoco LP and USAC allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:


•	Unitholders’ current proportionate ownership interest in each partnership will decrease;


•	the amount of cash available for distribution on each common unit or partnership security may decrease;


•	the ratio of taxable income to distributions may increase;


•	the relative voting strength of each previously outstanding common unit may be diminished; and


•	the market price of each partnership’s common units may decline.

The payment of distributions on any additional units issued by ETP, Sunoco LP and USAC may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

The consolidated debt level and debt agreements of ETP, Sunoco LP and USAC and those of their subsidiaries may limit the distributions we receive from ETP, Sunoco LP and USAC, as well as our future financial and operating flexibility.

ETP’s, Sunoco LP’s and USAC’s levels of indebtedness affect their operations in several ways, including, among other things:


•	a significant portion of ETP’s, Sunoco LP’s and USAC’s and their subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;


•	covenants contained in ETP’s, Sunoco LP’s and USAC’s and their subsidiaries’ existing debt agreements require ETP, Sunoco LP, USAC and their subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;


•	ETP’s, Sunoco LP’s and USAC’s and their subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;

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•	ETP, Sunoco LP and USAC may be at a competitive disadvantage relative to similar companies that have less debt;


•	ETP, Sunoco LP and USAC may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;


•	failure by ETP, Sunoco LP, USAC or their subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETP’s, Sunoco LP’s and USAC’s ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.

Our subsidiaries are not prohibited from competing with us.

Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETP, Sunoco LP and USAC, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.

In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $7.8 billion of our consolidated debt as of June 30, 2018 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.

Risks Related to Conflicts of Interest

Although we control ETP, Sunoco LP and USAC through our ownership of their general partners, ETP’s, Sunoco LP’s and USAC’s general partners owe fiduciary duties to ETP and ETP’s unitholders, Sunoco LP and Sunoco LP’s unitholders and USAC and USAC’s unitholders respectively, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETP, Sunoco LP and USAC and their respective limited partners, on the other hand. The directors and officers of ETP’s, Sunoco LP’s and USAC’s General Partners have fiduciary duties to manage ETP, Sunoco LP and USAC, respectively, in a manner beneficial to us. At the same time, the General Partners have fiduciary duties to manage ETP, Sunoco LP and USAC in a manner beneficial to ETP, Sunoco LP and USAC and their respective limited partners. The boards of directors of ETP’s, Sunoco LP’s and USAC’s General Partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

For example, conflicts of interest with ETP, Sunoco LP and USAC may arise in the following situations:


•	the allocation of shared overhead expenses to ETP, Sunoco LP, USAC and us;


•	the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, Sunoco LP and USAC, on the other hand;


•	the determination of the amount of cash to be distributed to ETP’s, Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of ETP’s, Sunoco LP’s and USAC’s businesses;


•	the determination whether to make borrowings under ETP’s, Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective partners;


•	the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETP, Sunoco LP and USAC is made available for ETP, Sunoco LP and USAC to pursue; and


•	any decision we make in the future to engage in business activities independent of ETP, Sunoco LP and USAC.

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The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s, Sunoco LP’s or USAC’s respective general partners.

Conflicts of interest may arise because of the relationships among ETP, Sunoco LP, USAC, their general partners and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors or officers are also directors and/or officers of ETP’s general partner, Sunoco LP’s general partner or USAC’s general partner, and have fiduciary duties to manage the respective businesses of ETP, Sunoco LP and USAC in a manner beneficial to ETP, Sunoco LP, USAC and their respective Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.

Risks Related to the Businesses of our Subsidiaries

Since our cash flows consist exclusively of distributions from our subsidiaries, risks to the businesses of our subsidiaries are also risks to us. We have set forth below risks to the businesses of our subsidiaries, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash they are able to distribute to us.

ETP, Sunoco LP and USAC are exposed to the credit risk of their respective customers and derivative counterparties, and an increase in the nonpayment and nonperformance by their respective customers or derivative counterparties could reduce their respective ability to make distributions to their Unitholders, including to us.

The risks of nonpayment and nonperformance by ETP’s, Sunoco LP’s and USAC’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP, Sunoco LP and USAC are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers, especially during the current low commodity price environment impacting many oil and gas producers. As a result, the current commodity price volatility and the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s, Sunoco LP’s and USAC’s customers. To the extent one or more of our customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial increase in the nonpayment and nonperformance by ETP’s, Sunoco LP’s or USAC’s customers could have a material adverse effect on ETP’s, Sunoco LP’s or USAC’s respective results of operations and operating cash flows.

ETP, Sunoco LP and USAC may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.

ETP, Sunoco LP and USAC have strategies that contemplate growth through the development and acquisition of a wide range of midstream, retail and wholesale fuel distribution assets and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP, Sunoco LP and USAC regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP, Sunoco LP and USAC believe will present opportunities to realize synergies and increase cash flow.

Consistent with their strategies, managements of ETP, Sunoco LP and USAC may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP, Sunoco LP and USAC management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP, Sunoco LP and USAC believe it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot assure that ETP’s, Sunoco LP’s or USAC’s acquisition efforts will be successful or that any acquisition will be completed on favorable terms.

In addition, ETP, Sunoco LP and USAC are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP, Sunoco LP or USAC losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s, Sunoco LP’s and USAC’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s, Sunoco LP’s and USAC’s results of operations.

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An impairment of goodwill and intangible assets could reduce our earnings.

As of June 30, 2018, our consolidated balance sheets reflected $5.17 billion of goodwill and $6.09 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

If ETP, Sunoco LP and USAC do not make acquisitions on economically acceptable terms, their future growth could be limited.

ETP’s, Sunoco LP’s and USAC’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.

ETP, Sunoco LP and USAC may be unable to make accretive acquisitions for any of the following reasons, among others:


•	inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;


•	inability to raise financing for such acquisitions on economically acceptable terms; or


•	inability to outbid by competitors, some of which are substantially larger than ETP, Sunoco LP or USAC and may have greater financial resources and lower costs of capital.

Furthermore, even if ETP, Sunoco LP or USAC consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP, Sunoco LP or USAC may:


•	fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;


•	decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;


•	significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;


•	encounter difficulties operating in new geographic areas or new lines of business;


•	incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;


•	be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;


•	less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or


•	incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

If ETP, Sunoco LP and USAC consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP, Sunoco LP and USAC determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that ETP, Sunoco LP and USAC will consider.

USAC’s customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, expanding the amount of compression units they currently own or using alternative technologies for enhancing crude oil production.

USAC’s customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using USAC’s compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to USAC's customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and USAC's customers may elect to use these alternative technologies instead of the gas lift compression services USAC provides. Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for USAC's

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compression services, which may have a material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution.

A significant portion of USAC's services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.

USAC's contracts typically have an initial term of between six months and five years, depending on the application and location of the compression unit. After the expiration of the applicable term, the contract continues on a month-to-month or longer basis until terminated by USAC or USAC's customers upon notice as provided for in the applicable contract. As of June 30, 2018, approximately 47% of USAC's compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts with USAC. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on USAC's business, results of operations, financial condition and cash available for distribution.

Risk Factors Relating to the Merger of ETE and ETP

Because the market price of ETE common units will fluctuate prior to the consummation of the merger, ETP common unitholders cannot be sure of the market value of the ETE common units they will receive as merger consideration relative to the value of ETP common units they exchange.

The market value of the merger consideration that ETP common unitholders will receive in the merger will depend on the trading price of ETE’s common units at the closing of the merger. The exchange ratio that determines the number of ETE common units that ETP common unitholders will receive as consideration in the merger is fixed. This means that there is no mechanism contained in the merger agreement that would adjust the number of ETE common units that ETP common unitholders will receive as the merger consideration based on any decreases or increases in the trading price of ETE common units. Unit price changes may result from a variety of factors (many of which are beyond ETE’s or ETP’s control), including:


•	changes in ETE’s and ETP’s business, operations and prospects;


•	changes in market assessments of ETE’s and ETP’s business, operations and prospects;


•	interest rates, general market, industry and economic conditions and other factors generally affecting the price of ETE common units; and


•	federal, state and local legislation, governmental regulation and legal developments in the businesses in which ETE and ETP operate.

Because the merger will be completed after the special meeting, at the time of the meeting, you will not know the exact market value of the ETE common units that you will receive upon completion of the merger. If ETE’s common unit price at the closing of the merger is less than ETE’s common unit price on the date on which the merger agreement was signed, then the market value of the merger consideration received by ETP unitholders will be less than contemplated at the time the merger agreement was signed.

The fairness opinion rendered to the ETP Conflicts Committee by Barclays Capital Inc. (“Barclays”) was based on Barclays’ financial analysis and considered factors such as market and other conditions then in effect, financial forecasts and other information made available to Barclays as of the date of the opinion. As a result, the opinion does not reflect changes in events or circumstances after the date of such opinion. The ETP Conflicts Committee has not obtained, and does not expect to obtain, an updated fairness opinion from Barclays reflecting changes in circumstances that may have occurred since the signing of the merger agreement.

The fairness opinion rendered to the ETP Conflicts Committee by Barclays was provided in connection with, and at the time of, the evaluation of the merger and the merger agreement by the ETP Conflicts Committee. The opinion was based on the financial analyses performed, which considered market and other conditions then in effect, financial forecasts and other information made available to Barclays as of the date of the opinion, which may have changed, or may change, after the date of the opinion. The ETP Conflicts Committee has not obtained an updated opinion from Barclays following the date of the merger agreement and does not expect to obtain an updated opinion prior to completion of the merger. Changes in the operations and prospects of ETE or ETP, general market and economic conditions and other factors that may be beyond the control of ETE and ETP, and on which the fairness opinion was based, may have altered the value of ETE or ETP or the prices of ETE common units or ETP common units since the date of such opinion, or may alter such values and prices by the time the merger is completed. The opinion does not speak as of any date other than the date of the opinion. For a description of the opinion that Barclays rendered to the ETP Conflicts Committee in connection with the merger, please read the proxy statement/prospectus when it becomes available.

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ETP and ETE may be targets of securities class action and derivative lawsuits, which could result in substantial costs and may delay or prevent the completion of the merger.

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements in an effort to enjoin the merger or seek monetary relief from ETP or ETE. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. ETP and ETE cannot predict the outcome of these lawsuits, or others, nor can they predict the amount of time and expense that will be required to resolve such litigation. An unfavorable resolution of any such litigation surrounding the merger could delay or prevent its consummation. In addition, the costs defending the litigation, even if resolved in ETP’s or ETE’s favor, could be substantial and such litigation could distract ETP and ETE from pursuing the consummation of the merger and other potentially beneficial business opportunities.

Maintaining credit ratings is under the control of ratings agencies, which are independent third parties. There can be no assurances that the combined partnership will qualify for an investment-grade credit rating, and the failure to qualify for an investment-grade credit rating could negatively impact the combined partnership’s access to capital and costs of doing business.

In connection with the completion of the merger, ratings agencies may reevaluate ETE’s and ETP’s credit ratings. It is expected that the combined partnership will qualify for an investment-grade credit rating consistent with ETP’s current rating; however, credit rating agencies perform independent analysis when assigning credit ratings and there can be no assurances that such ratings will be achieved in connection with the merger or maintained in the future. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. The combined company’s ratings upon completion of the merger will reflect each rating organization’s opinion of the combined company’s financial strength, operating performance and ability to meet the obligations associated with its securities. In addition, the trading market for ETE’s and ETP’s securities depends, in part on the research and reports that third-party securities analysts publish about ETE and ETP and the industry in which they participate. In connection with the completion of the merger, one or more of these analysts could downgrade ETE or ETP securities or issue other negative commentary about ETE or ETP and the industry in which they participate, which could cause the trading price of such securities to decline.

Failure to qualify for an investment-grade credit rating or a downgrade may increase ETE’s and ETP’s cost of borrowing, may negatively impact ETE’s and ETP’s ability to raise additional debt capital, may negatively impact ETE’s and ETP’s ability to successfully compete, and may negatively impact the willingness of counterparties to deal with ETE and ETP, each of which could have a material adverse effect on the business, financial condition, results of operations and cash flows of ETE and ETP, as well as the market price of their respective securities.

Credit rating agencies continue to review the criteria for industry sectors and various debt ratings on an ongoing basis and may make changes to those criteria from time to time. Ratings are subject to revision or withdrawal at any time by the rating agencies. The credit rating of the combined company will be subject to ongoing evaluation by credit rating agencies, and downgrades in the combined company’s ratings could adversely affect the combined company’s business, cash flows, financial condition, operating results and share and debt prices.

Directors and executive officers of ETP have certain interests that are different from those of ETP unitholders generally.

Directors and executive officers of ETP are parties to agreements or participants in other arrangements that give them interests in the merger that may be different from, or in addition to, your interests as a unitholder of ETP. In addition, certain of the directors and executive officers of ETP are also directors or executive officers at ETE, and each of the directors of ETP is appointed by ETE, as the sole member of ETP LLC. These and other different interests will be described in the proxy statement/prospectus when it becomes available. ETP unitholders should consider these interests in voting on the merger.

The ETP partnership agreement limits the duties of ETP GP to ETP common unitholders and restricts the remedies available to unitholders for actions taken by ETP GP that might otherwise constitute breaches of its duties.

ETP LLC, the general partner of ETP GP, the general partner of ETP, is owned by ETE. In light of potential conflicts of interest between ETE and ETP GP, on the one hand, and ETP and the ETP common unitholders, on the other hand, the ETP Board submitted the merger and related matters to the ETP Conflicts Committee for, among other things, review, evaluation, negotiation and possible approval of a majority of its members, which is referred to as “Special Approval” in the ETP partnership agreement. In addition, the merger is conditioned upon the approval of holders of a majority of ETP common units held by persons other than ETP GP and its affiliates (referred to herein as “unaffiliated ETP unitholder approval”). Under the ETP partnership agreement:


•	any resolution or course of action by ETP GP or its affiliates in respect of a conflict of interest is permitted and deemed approved by all partners of ETP (i.e. the ETP unitholders), and will not constitute a breach of the ETP partnership agreement

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or of any duty stated or implied by law or equity, if the resolution or course of action is approved by Special Approval or unaffiliated ETP unitholder approval; and

•

ETP GP may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants selected by it, and any act taken or omitted to be taken in reliance upon the opinion of such persons as to matters that ETP GP reasonably believes to be within such person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.

The ETP Conflicts Committee reviewed, negotiated and evaluated the merger agreement, the merger and related matters on behalf of the ETP common unitholders and ETP. Among other things, the ETP Conflicts Committee unanimously determined in good faith that the merger agreement and the transactions contemplated thereby, including the merger, are in the best interests of ETP and the unaffiliated ETP common unitholders, approved the merger agreement and the transactions contemplated thereby, including the merger, and recommended the approval of the merger agreement and the transactions contemplated thereby, including the merger, to the ETP Board.

The duties of ETP GP, the ETP Board and the ETP Conflicts Committee to ETP common unitholders in connection with the merger are substantially limited by the ETP partnership agreement.

ETE common unitholders have limited voting rights and are not entitled to elect ETE’s general partner or the directors of ETE’s general partner. Following the closing, the Class A Units issued by ETE to its general partner, LE GP, LLC (“ETE GP”) concurrently with closing would result in ETE GP and its affiliates maintaining the same relative voting power following the merger as they have prior to the merger, until such time as Kelcy L. Warren is no longer an officer or director of ETE GP.

Unlike the holders of common stock in a corporation, ETE common unitholders have only limited voting rights on matters affecting ETE’s business, and therefore limited ability to influence ETE management’s decisions regarding its business. ETE common unitholders did not elect its general partner and will have no right to elect its general partner or the officers or directors of its general partner on an annual or other continuing basis. In addition, on matters where ETE common unitholders are entitled to vote, the ETE partnership agreement generally permits ETE GP and its affiliates to vote their ETE common units on such matters, together with unaffiliated ETE unitholders, as a single class. For example, the general partner of ETE may only be removed by the affirmative vote of holders of 66.7% of the ETE common units (including ETE GP and its affiliates), voting together as a single class. As of August 1, 2018, ETE GP and its affiliates collectively own approximately 31.0% of the outstanding ETE common units.

In connection with the closing of the merger and the issuance of the merger consideration to former ETP common unitholders, the percentage ownership of ETE GP and its affiliates of ETE common units is expected to be diluted to approximately 13.5%. However, at the closing of the merger, ETE will issue to ETE GP a number of new Class A Units necessary to ensure that ETE GP and its affiliates maintain the same relative voting power following the merger as they have prior to the merger. The Class A Units will not be entitled to distributions, will not have any economic attributes (other than the entitlement to $100 in the aggregate upon liquidation) and will not be convertible or exchangeable for ETE common units, but will generally vote as a single class with ETE common units. For so long as Mr. Warren continues as a director or officer of ETE GP, upon issuance of additional ETE common units following the merger, ETE will also issue additional Class A Units to ETE GP such that the Class A Units will continue to represent, in the aggregate, the same voting interest as they represent upon closing of the merger. The existence of the Class A Units from and after closing of the merger will therefore, in certain circumstances, reduce the voting power represented by an ETE common unit compared to a scenario in which the Class A Units had not been issued.

ETE common units to be received by ETP common unitholders as a result of the merger have different rights than ETP common units.

Following completion of the merger, ETP common unitholders will no longer hold ETP common units, but will instead be unitholders of ETE. There are important differences between the rights of ETP unitholders and the rights of ETE unitholders. See the proxy statement/prospectus when it becomes available for a discussion of the different rights associated with ETE common units and ETP common units.

The number of outstanding ETE common units will increase as a result of the merger, which could make it more difficult for ETE to pay the current level of quarterly distributions.

As of July 31, 2018, there were more than 1.158 billion ETE common units outstanding. ETE expects to issue approximately 1.50 billion common units in connection with the merger. Accordingly, the aggregate dollar amount required to pay the current per unit quarterly distribution on all ETE common units will increase, which could increase the likelihood that ETE will not have sufficient funds to pay the current level of quarterly distributions to all ETE unitholders. Using a $0.305 per ETE common unit distribution (the amount ETE has declared to pay with respect to the second fiscal quarter of 2018 on August 20, 2018 to holders of record as

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of August 6, 2018), the aggregate cash distribution paid to ETE unitholders totaled approximately $354 million, including a distribution of $1 million to ETE GP in respect of its general partner interest. Using the same $0.305 per ETE common unit distribution, the combined pro forma ETE distribution with respect to the second fiscal quarter of 2018, had the merger been completed prior to such distribution, would have resulted in total cash distributions of approximately $809 million, including a distribution of $1 million to ETE GP in respect of its general partner interest.

ETE and ETP will incur substantial transaction-related costs in connection with the merger, including fees paid to legal, financial and accounting advisors, filing fees and printing costs.

ETE and ETP expect to incur a number of non-recurring transaction-related costs associated with completing the merger. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, filing fees and printing costs. Thus, any net benefit of the merger may not be achieved in the near term, the long term or at all.

The merger is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all. Failure to complete the merger, or significant delays in completing the merger, could negatively affect the trading prices of ETE common units and ETP common units and the future business and financial results of ETE and ETP.

The completion of the merger is subject to a number of conditions, some of which are beyond the parties’ control. In addition, ETE and ETP can agree not to consummate the merger even if the ETP common unitholders approve the merger proposal and the conditions to the closing of the merger are otherwise satisfied.

The completion of the merger is not assured and is subject to risks, including the risk that the closing conditions are not satisfied, including that the approval of the merger by ETP common unitholders or by governmental agencies is not obtained or the occurrence of a material adverse change to the business or results of operations of ETE and ETP. The failure to satisfy conditions to the merger may prevent or delay the merger or otherwise result in the merger not occurring. The failure of the completion of the merger, or any significant delays in completing the merger, could cause the combined company not to realize, or delay the realization of, some or all of the benefits that the combined company expects to achieve from the merger, including those relating to the trading prices of ETE common units and ETP common units and the respective future business and financial results of ETE and ETP, which could be negatively affected, and each of which are subject to risks, including the following:


•	the parties may be liable for damages to one another under the terms and conditions of the merger agreement;


•	negative reactions from the financial markets, including declines in the price of ETE common units or ETP common units due to the fact that current prices may reflect a market assumption that the merger will be completed;


•	having to pay certain significant costs relating to the merger, including, in certain circumstances, the reimbursement by ETP of up to $30 million of ETE’s expenses and a termination fee of $750 million less any previous expense reimbursements by ETP; and


•	the attention of management of ETE and ETP will have been diverted to the merger rather than other strategic opportunities that could have been beneficial to that organization.

ETP is subject to provisions in the merger agreement that limit its ability to pursue alternatives to the merger, which could discourage a potential competing acquirer of ETP from making a favorable alternative transaction proposal and, in specified circumstances under the merger agreement, would require ETP to reimburse up to $30 million of ETE’s out-of-pocket expenses and pay a termination fee to ETE of $750 million less any previous expense reimbursements.

Under the merger agreement, ETP is restricted from entering into alternative transactions. Unless and until the merger agreement is terminated, subject to specified exceptions (which will be discussed in more detail in the proxy statement/prospectus when it becomes available), ETP is restricted from soliciting, initiating, knowingly facilitating, knowingly encouraging or knowingly inducing or taking any other action intended to lead to any inquiries or any proposals that constitute or could reasonably be expected to lead to a proposal or offer for a competing acquisition proposal with any person. In addition, ETP may not grant any waiver or release of any standstill or similar agreement with respect to any units of ETP or any of its subsidiaries. Under the merger agreement, in the event of a potential change by the ETP Board of its recommendation with respect to the proposed merger in light of a superior proposal, ETP must provide ETE with five calendar days’ notice to allow ETE to propose an adjustment to the terms and conditions of the merger agreement. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of ETP from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher per unit market value than the merger consideration, or might result in a potential competing acquirer of ETP proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in specified circumstances.

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If the merger agreement is terminated under specified circumstances, including due to an adverse recommendation change having occurred or ETP entering into an agreement relating to a superior proposal, ETP will be required to pay ETE a termination fee of $750 million, less any expenses of ETE previously reimbursed by ETP. If the merger agreement is terminated under specified circumstances, including if the ETP unitholder approval is not obtained or if ETP breaches certain of its obligations under the merger agreement, then ETP will be required to pay all of the reasonably documented out-of-pocket expenses incurred by ETE and its affiliates in connection with the merger agreement and the transactions contemplated thereby, up to a maximum amount of $30 million. Following payment of the termination fee or the reimbursement of expenses, as applicable, ETP will not be obligated to pay any additional expenses incurred by ETE or its affiliates. If such a termination fee is payable, the payment of this fee could have material and adverse consequences to the financial condition and operations of ETP. For a discussion of the restrictions on soliciting or entering into an alternative transaction and the ability of the ETP Board to change its recommendation.

If a governmental authority asserts objections to the merger, ETE and ETP may be unable to complete the merger or, in order to do so, ETE and ETP may be required to comply with material restrictions or satisfy material conditions.

The closing of the merger is subject to the condition that there is no law, injunction, judgment or ruling by a governmental authority in effect enjoining, restraining, preventing or prohibiting the merger contemplated by the merger agreement. If a governmental authority asserts objections to the merger, ETE or ETP may be required to divest assets or accept other remedies in order to complete the merger. There can be no assurance as to the cost, scope or impact of the actions that may be required to address any governmental authority objections to the merger. If ETE or ETP takes such actions, it could be detrimental to it or to the combined organization following the consummation of the merger. Furthermore, these actions could have the effect of delaying or preventing completion of the proposed merger or imposing additional costs on or limiting the revenues or cash available for distribution of the combined organization following the consummation of the merger.

Additionally, state attorneys general could seek to block or challenge the merger as they deem necessary or desirable in the public interest at any time, including after completion of the transaction. In addition, in some circumstances, a third party could initiate a private action under antitrust laws challenging or seeking to enjoin the merger, before or after it is completed. ETE may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

ETE and ETP are subject to contractual interim operating restrictions while the proposed merger is pending, which could adversely affect each party’s business and operations.

Under the terms of the merger agreement, each of ETE and ETP is subject to certain restrictions on the conduct of its business prior to completing the merger, which may adversely affect its ability to execute certain of its business strategies. Such limitations could negatively affect each party’s businesses and operations prior to the completion of the merger. For a discussion of these restrictions, please read the proxy statement/prospectus when it becomes available.

If the merger is approved by ETP common unitholders, the date on which ETP unitholders will receive the merger consideration is uncertain.

As described in this proxy statement/prospectus, completing the proposed merger is subject to several conditions, not all of which are controllable or waivable by ETE or ETP. Accordingly, if the proposed merger is approved by ETP unitholders, the date on which ETP common unitholders will receive the merger consideration depends on the completion date of the merger, which is uncertain.

ETP common unitholders will have a reduced ownership in the combined organization after the merger.

When the merger occurs, each ETP common unitholder that receives ETE common units will become a unitholder of ETE with a percentage ownership of the combined organization that is smaller than such unitholder’s percentage ownership of ETP prior to the merger. Assuming that the merger had been completed on August 1, 2018, current ETP common unitholders would have owned approximately 56% of the combined entity based on the number of ETP common units and ETE common units outstanding at that date.

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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)
10.1		Registration Rights Agreement, dated as of April 2, 2018, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression Holdings, LLC. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed April 3, 2018)
10.2***		Amended and Restated Energy Transfer Partners, L.L.C. Annual Bonus Plan
12.1*		Computation of Ratio of Earnings to Fixed Charges.
31.1*		Certification of President 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 President pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy 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. Filed herewith.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		ENERGY TRANSFER EQUITY, L.P.

		By:	LE GP, LLC, its General Partner

Date:	August 9, 2018	By:	/s/ Thomas E. Long
			Thomas E. Long
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)