Edgar Filing: Energy Transfer Partners, L.P.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

Document

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 1-31219

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)



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

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

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

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

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

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

At August 3, 2018, the registrant had 1,166,403,685 Common Units outstanding.

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FORM 10-Q

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS



PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets	1

Consolidated Statements of Operations	3

Consolidated Statements of Comprehensive Income	4

Consolidated Statement of Equity	5

Consolidated Statements of Cash Flows	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	43

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	65

ITEM 4. CONTROLS AND PROCEDURES	67

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	68

ITEM 1A. RISK FACTORS	68

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	73

ITEM 6. EXHIBITS	74

SIGNATURE	76

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P. (the “Partnership” or “ETP”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 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 used

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

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

	Citrus		Citrus, LLC

	DOJ		United States Department of Justice

	EPA		United States Environmental Protection Agency

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

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

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

	ETP Holdco		ETP Holdco Corporation

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

	Exchange Act		Securities Exchange Act of 1934

	FEP		Fayetteville Express Pipeline LLC

	FERC		Federal Energy Regulatory Commission

	FGT		Florida Gas Transmission Company, LLC

	GAAP		accounting principles generally accepted in the United States of America

	HPC		RIGS Haynesville Partnership Co.

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	IDRs		incentive distribution rights

	Legacy ETP Preferred Units		legacy ETP Series A cumulative convertible preferred units

	LIBOR		London Interbank Offered Rate

	MBbls		thousand barrels

	MEP		Midcontinent Express Pipeline LLC

	MTBE		methyl tertiary butyl ether

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

	NYMEX		New York Mercantile Exchange

	OSHA		federal Occupational Safety and Health Act

	OTC		over-the-counter

	Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries

	PennTex		PennTex Midstream Partners, LP

	PES		Philadelphia Energy Solutions

	Regency		Regency Energy Partners LP

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

	RIGS		Regency Intrastate Gas LP

	Rover		Rover Pipeline LLC, a subsidiary of ETP

	SEC		Securities and Exchange Commission

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

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

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

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

	Sunoco Logistics		Sunoco Logistics Partners L.P.

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC, a subsidiary of Panhandle

	USAC		USA Compression Partners, LP

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

iii

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	June 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	494		$	306
Accounts receivable, net	3,684			3,946
Accounts receivable from related companies	334			318
Inventories	1,256			1,589
Income taxes receivable	172			135
Derivative assets	57			24
Other current assets	550			210
Total current assets	6,547			6,528

Property, plant and equipment	69,637			67,699
Accumulated depreciation and depletion	(9,861		)	(9,262		)
	59,776			58,437

Advances to and investments in unconsolidated affiliates	3,636			3,816
Other non-current assets, net	762			758
Intangible assets, net	4,988			5,311
Goodwill	2,861			3,115
Total assets	$	78,570		$	77,965

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	June 30, 2018		December 31, 2017
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,488	$	4,126
Accounts payable to related companies	329		209
Derivative liabilities	385		109
Accrued and other current liabilities	2,284		2,143
Current maturities of long-term debt	155		407
Total current liabilities	6,641		6,994

Long-term debt, less current maturities	33,741		32,687
Non-current derivative liabilities	135		145
Deferred income taxes	2,917		2,883
Other non-current liabilities	1,079		1,084

Commitments and contingencies
Redeemable noncontrolling interests	21		21

Equity:
Limited Partners:
Series A Preferred Unitholders	958		944
Series B Preferred Unitholders	556		547
Series C Preferred Unitholders	442		—
Common Unitholders	25,546		26,531
General Partner	359		244
Accumulated other comprehensive income	4		3
Total partners’ capital	27,865		28,269
Noncontrolling interest	6,171		5,882
Total equity	34,036		34,151
Total liabilities and equity	$	78,570	$	77,965

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

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ENERGY TRANSFER PARTNERS, 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			1,485			4,171			3,032
Crude sales	4,241			2,345			7,495			4,887
Gathering, transportation and other fees	1,464			1,067			2,861			2,091
Refined product sales	413			304			852			775
Other	127			353			225			652
Total revenues	9,410			6,576			17,690			13,471
COSTS AND EXPENSES:
Cost of products sold	7,140			4,624			13,128			9,674
Operating expenses	627			539			1,231			1,031
Depreciation, depletion and amortization	588			557			1,191			1,117
Selling, general and administrative	112			120			224			230
Total costs and expenses	8,467			5,840			15,774			12,052
OPERATING INCOME	943			736			1,916			1,419
OTHER INCOME (EXPENSE):
Interest expense, net	(358		)	(336		)	(704		)	(668		)
Equity in earnings (losses) of unconsolidated affiliates	106			(61		)	34			12
Gain on Sunoco LP common unit repurchase	—			—			172			—
Loss on deconsolidation of CDM	(86		)	—			(86		)	—
Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Other, net	46			61			106			80
INCOME BEFORE INCOME TAX EXPENSE	671			375			1,510			823
Income tax expense	69			79			29			134
NET INCOME	602			296			1,481			689
Less: Net income attributable to noncontrolling interest	170			94			334			156
NET INCOME ATTRIBUTABLE TO PARTNERS	432			202			1,147			533
Series A Preferred Unitholders’ interest in net income	15			—			30			—
Series B Preferred Unitholders’ interest in net income	9			—			18			—
Series C Preferred Unitholders’ interest in net income	6			—			6			—
General Partner’s interest in net income	402			251			804			457
Class H Unitholder’s interest in net income	—			—			—			93
Common Unitholders’ interest in net income (loss)	$	—		$	(49	)	$	289		$	(17	)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)
Diluted	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)

* As adjusted. See Note 1.

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

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ENERGY TRANSFER PARTNERS, 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	$	602	$	296		$	1,481		689
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	—		1			(2		)	3
Actuarial loss 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	604		295			1,484			688
Less: Comprehensive income attributable to noncontrolling interest	170		94			334			156
Comprehensive income attributable to partners	$	434	$	201		$	1,150		$	532

* As adjusted. See Note 1.

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2018

(Dollars in millions)

(unaudited)



	Limited Partners
	Series A Preferred Units			Series B Preferred Units			Series C Preferred Units		Common Units			General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2017	$	944		$	547		$	—	$	26,531		$	244		$	3		$	5,882		$	34,151
Distributions to partners	(15		)	(9		)	—		(1,315		)	(672		)	—			—			(2,011		)
Distributions to noncontrolling interest	—			—			—		—			—			—			(359		)	(359		)
Units issued for cash	—			—			436		39			—			—			—			475
Capital contributions from noncontrolling interest	—			—			—		—			—			—			318			318
Repurchases of common units	—			—			—		(24		)	—			—			—			(24		)
Other comprehensive income, net of tax	—			—			—		—			—			3			—			3
Other, net	(1		)	—			—		26			(17		)	(2		)	(4		)	2
Net income	30			18			6		289			804			—			334			1,481
Balance, June 30, 2018	$	958		$	556		$	442	$	25,546		$	359		$	4		$	6,171		$	34,036

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Six Months Ended June 30,
	2018			2017*
OPERATING ACTIVITIES
Net income	$	1,481		$	689
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,191			1,117
Deferred income taxes	52			121
Non-cash compensation expense	41			38
Gain on Sunoco LP common unit repurchase	(172		)	—
Loss on deconsolidation of CDM	86			—
Distributions on unvested awards	(17		)	(15		)
Equity in earnings of unconsolidated affiliates	(34		)	(12		)
Distributions from unconsolidated affiliates	215			197
Other non-cash	(122		)	(98		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	229			(387		)
Net cash provided by operating activities	2,950			1,650
INVESTING ACTIVITIES
Cash proceeds from CDM contribution	1,227			—
Cash proceeds from Sunoco LP common unit repurchase	540			—
Cash proceeds from Bakken pipeline transaction	—			2,000
Cash paid for acquisition of PennTex noncontrolling interest	—			(280		)
Cash paid for all other acquisitions	(29		)	(261		)
Capital expenditures, excluding allowance for equity funds used during construction	(3,409		)	(2,842		)
Contributions in aid of construction costs	60			10
Contributions to unconsolidated affiliates	(13		)	(225		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	31			94
Proceeds from the sale of assets	2			25
Other	—			(7		)
Net cash used in investing activities	(1,591		)	(1,486		)
FINANCING ACTIVITIES
Proceeds from borrowings	12,476			11,466
Repayments of debt	(12,018		)	(10,953		)
Cash paid to affiliate notes	—			(255		)
Common units issued for cash	39			990
Preferred units issued for cash	436			—
Capital contributions from noncontrolling interest	318			456
Distributions to partners	(2,011		)	(1,702		)
Distributions to noncontrolling interest	(359		)	(186		)
Repurchases of common units	(24		)	—
Redemption of Legacy ETP Preferred Units	—			(53		)
Debt issuance costs	(38		)	(20		)
Other	10			5
Net cash used in financing activities	(1,171		)	(252		)
Increase (decrease) in cash and cash equivalents	188			(88		)
Cash and cash equivalents, beginning of period	306			360
Cash and cash equivalents, end of period	$	494		$	272

* As adjusted. See Note 1.

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)


1.	ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer Partners, L.P. (“ETP”) is a consolidated subsidiary of ETE. 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.

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction (the “Sunoco Logistics Merger”), with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the Sunoco Logistics Merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.

The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).

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

•

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


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


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


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


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


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


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


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


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

•

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

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

We currently have the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

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

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements of Energy Transfer Partners, L.P. for the year ended December 31, 2017, included in the Partnership’s Annual Report on Form 10-K 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.

The historical common units and net income per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.

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

Change in Accounting Policy

Inventory Accounting Change

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. 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.

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



	Three Months Ended 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 ⁽¹⁾	$	4,628		$	(4	)	$	4,624		$	9,707		$	(33	)	$	9,674
Operating income	732			4			736			1,386			33			1,419
Income before income tax expense	371			4			375			790			33			823
Net income	292			4			296			656			33			689
Net income attributable to partners	199			3			202			523			10			533
Net loss per common unit – basic	(0.04		)	—			(0.04		)	(0.04		)	0.02			(0.02		)
Net loss per common unit – diluted	(0.04		)	—			(0.04		)	(0.04		)	0.02			(0.02		)
Comprehensive income	291			4			295			655			33			688
Comprehensive income attributable to partners	198			3			201			522			10			532

⁽¹⁾As originally reported amounts reflect certain reclassifications made to conform to the current year presentation.

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	$	656		$	33		$	689
Inventory valuation adjustments	56			(56		)	—
Net change in operating assets and liabilities, net of effects from acquisitions (change in inventories)	(410		)	23			(387		)

Revenue Recognition Standard

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

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

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

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

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

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



	Three Months Ended 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	1,464		1,611		(147		)	2,861		3,194		(333		)
Refined product sales	413		413		—			852		852		—
Other	127		127		—			225		225		—

Costs and expenses:
Cost of products sold	$	7,140	$	7,287	$	(147	)	$	13,128	$	13,461	$	(333	)
Operating expenses	627		617		10			1,231		1,206		25

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

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guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

ASU 2018-02

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


2.	ACQUISITIONS AND OTHER INVESTING TRANSACTIONS

CDM Contribution

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

Prior to the CDM Contribution, the CDM entities were indirect wholly-owned subsidiaries of ETP. Beginning April 2018, ETP’s consolidated financial statements reflected an equity method investment in USAC. CDM’s assets and liabilities were not reflected as held for sale, nor were CDM’s results reflected as discontinued operations in these financial statements. At June 30, 2018, the carrying value of ETP’s investment in USAC was $399 million, which is reflected in the all other segment. ETP recorded a $86 million loss on the deconsolidation of CDM including a $45 million accrual related to the indemnification of USAC related to an ongoing CDM sales and use tax audit.

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


3.	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES

HPC

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

Sunoco LP

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

As of June 30, 2018, ETP owns 26.2 million Sunoco LP common units representing 31.8% of Sunoco LP’s total outstanding common units. Our investment in Sunoco LP is reflected in the all other segment. As of June 30, 2018, the carrying value of our investment in Sunoco LP is $535 million.

USAC

As of June 30, 2018, ETP owns 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests in USAC. USAC provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. Our investment in USAC is reflected in the all other segment. As of June 30, 2018, the carrying value of our investment in USAC is $399 million.

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4.	CASH AND CASH EQUIVALENTS

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

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

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



	Six Months Ended June 30,
	2018			2017*
Accounts receivable	$	236		$	88
Accounts receivable from related companies	156			(115		)
Inventories	299			160
Other current assets	(375		)	77
Other non-current assets, net	(3		)	(39		)
Accounts payable	(465		)	(286		)
Accounts payable to related companies	(99		)	131
Accrued and other current liabilities	249			(389		)
Other non-current liabilities	(2		)	7
Derivative assets and liabilities, net	233			(21		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	229		$	(387	)

* As adjusted. See Note 1.

Non-cash investing and financing activities are as follows:



	Six Months Ended June 30,
	2018		2017
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,007	$	1,363
USAC limited partner interests received in the CDM Contribution (see Note 2)	411		—
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—	$	988


5.	INVENTORIES

Inventories consisted of the following:



	June 30, 2018		December 31, 2017
Natural gas, NGLs and refined products	$	434	$	733
Crude oil	571		551
Spare parts and other	251		305
Total inventories	$	1,256	$	1,589

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We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.


6.	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 was $33.64 billion and $33.90 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $34.28 billion and $33.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the 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	300			300			—
Total commodity derivatives	413			334			79
Other non-current assets	21			14			7
Total assets	$	434		$	348		$	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	(316		)	(316		)	—
Refined Products – Futures	(5		)	(5		)	—
Crude – Forwards/Swaps	(307		)	(307		)	—
Total commodity derivatives	(776		)	(713		)	(63		)
Total liabilities	$	(923	)	$	(713	)	$	(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			—
Crude:
Forwards/Swaps	2			2			—
Futures	2			2			—
Total commodity derivatives	320			276			44
Other non-current assets	21			14			7
Total assets	$	341		$	290		$	51
Liabilities:
Interest rate derivatives	$	(219	)	$	—		$	(219	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(24		)	(24		)	—
Swing Swaps IFERC	(15		)	(1		)	(14		)
Fixed Swaps/Futures	(57		)	(57		)	—
Forward Physical Swaps	(2		)	—			(2		)
Power – Forwards	(22		)	—			(22		)
NGLs – Forwards/Swaps	(186		)	(186		)	—
Refined Products – Futures	(25		)	(25		)	—
Crude:
Forwards/Swaps	(6		)	(6		)	—
Futures	(1		)	(1		)	—
Total commodity derivatives	(338		)	(300		)	(38		)
Total liabilities	$	(557	)	$	(300	)	$	(257	)


7.	NET INCOME (LOSS) PER LIMITED PARTNER UNIT

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Net income	$	602		$	296		$	1,481		$	689
Less: Income attributable to noncontrolling interest	170			94			334			156
Net income, net of noncontrolling interest	432			202			1,147			533
Series A Preferred Unitholders’ interest in net income	15			—			30			—
Series B Preferred Unitholders’ interest in net income	9			—			18			—
Series C Preferred Unitholders’ interest in net income	6			—			6			—
General Partner’s interest in net income	402			251			804			457
Class H Unitholder’s interest in net income	—			—			—			93
Common Unitholders’ interest in net income (loss)	—			(49		)	289			(17		)
Additional (earnings) distributions allocated to General Partner	(1		)	15			(3		)	12
Distributions on employee unit awards, net of allocation to General Partner	(7		)	(6		)	(15		)	(13		)
Net income (loss) available to Common Unitholders	$	(8	)	$	(40	)	$	271		$	(18	)
Weighted average Common Units – basic	1,165.4			1,021.7			1,164.6			922.5
Basic net income (loss) per Common Unit	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)

Weighted average Common Units – diluted	1,165.4			1,021.7			1,169.4			922.5
Diluted net income (loss) per Common Unit	$	(0.01	)	$	(0.04	)	$	0.23		$	(0.02	)

* As adjusted. See Note 1.

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


8.	DEBT OBLIGATIONS

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 our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.

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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.

Credit Facilities and Commercial Paper

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 $1.00 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%.

Compliance with Our Covenants

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


9.	EQUITY

The changes in outstanding common units during the six months ended June 30, 2018 were as follows:



	Number of Units
Number of common units at December 31, 2017	1,164.1
Common units issued in connection with the distribution reinvestment plan	2.1
Common units issued in connection with certain transactions	1.3
Issuance of common units under equity incentive plans	0.1
Repurchases of common units in open-market transactions	(1.2	)
Number of common units at June 30, 2018	1,166.4

Equity Distribution Program

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

Distribution Reinvestment Program

During the six months ended June 30, 2018, distributions of $39 million were reinvested under the Partnership’s distribution reinvestment plan.

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Preferred Units

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

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.

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

Series D Preferred Units Issuance

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

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

Cash Distributions

Under our limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

Distributions on common units declared and/or paid by the Partnership 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 agreed to relinquish its right to the following amounts of incentive distributions 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/or paid by the Partnership subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
Series A Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	15.451
June 30, 2018	August 1, 2018	August 15, 2018	31.250
Series B Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	16.378
June 30, 2018	August 1, 2018	August 15, 2018	33.125
Series C Preferred Units
June 30, 2018	August 1, 2018	August 15, 2018	$	0.56337

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
Total AOCI, net of tax	$	4		$	3


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


10.	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 $3 million and $70 million, respectively, of deferred benefit adjustments as the result of a state statutory rate reduction.


11.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Guarantee of Sunoco LP Notes

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

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


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


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


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

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

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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.

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Rental expense	$	22	$	19	$	39	$	39

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 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.

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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. 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

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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.

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

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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.

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 $52 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

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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.

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

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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. Since 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.

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•

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	$	42	$	36
Non-current	276		314
Total environmental liabilities	$	318	$	350

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

During the three months ended June 30, 2018 and 2017, the Partnership recorded $6 million and $7 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2018 and 2017, the Partnership recorded $11 million and $13 million, respectively, of expenditures related to environmental 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.

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Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health 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 Partnership’s consolidated financial statements reflect the following six reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes:


•	intrastate transportation and storage;


•	interstate transportation and storage;


•	midstream;


•	NGL and refined products transportation and services;


•	crude oil transportation and services; and


•	all other.

Note 15 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.

Intrastate transportation and storage revenue

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

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

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

Interstate transportation and storage revenue

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

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

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

Midstream revenue

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

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

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

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


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

•

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

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

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

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

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deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.

NGL and refined products transportation and services revenue

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

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

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

Crude oil transportation and services revenue

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

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

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

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

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

All other revenue

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

Contract Balances with Customers

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

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. As of June 30, 2018 and January 1, 2018, no contract assets have been recognized.

The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. As of June 30, 2018, the Partnership had $235 million in deferred revenues representing the current value of our future performance obligations.

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.

As of June 30, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $40.32 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	$	2,598	$	5,048	$	4,604	$	28,071	$	40,321

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

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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.


13.	DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

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

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

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

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

We 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 financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

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The following table details our outstanding commodity-related derivatives:



	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	5,360		2018-2019	(4,700	)	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	44,190		2018-2019	9,172		2018-2019
Refined Products (MBbls) – Futures	(1,076	)	2018-2019	(3,783	)	2018-2019
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 our anticipated debt issuances.

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



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	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 terms of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

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

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

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

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

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Derivative Summary

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



	Fair Value of Derivative Instruments
	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	106		44		(422		)	(55		)
Interest rate derivatives	—		—		(147		)	(219		)
	413		306		(921		)	(555		)
Total derivatives	$	413	$	320	$	(923	)	$	(557	)

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



		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	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)	106			44			(422		)	(55		)
Broker cleared derivative contracts	Other current assets (liabilities)	307			276			(354		)	(283		)
Total gross derivatives		413			320			(923		)	(557		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(49		)	(20		)	49			20
Counterparty netting	Other current assets (liabilities)	(306		)	(263		)	306			263
Total net derivatives		$	58		$	37		$	(568	)	$	(274	)

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

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



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		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	(300		)	7			(373		)	(3		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Embedded derivatives	Other, net	—			—			—			1
Total		$	(264	)	$	(3	)	$	(268	)	$	4


14.	RELATED PARTY TRANSACTIONS

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Affiliated revenues	$	222	$	133	$	508	$	251

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The following table summarizes the related company balances on our consolidated balance sheets:



	June 30, 2018		December 31, 2017
Accounts receivable from related companies:
Sunoco LP	$	184	$	219
FGT	18		11
Other	132		88
Total accounts receivable from related companies:	$	334	$	318

Accounts payable to related companies:
Sunoco LP	$	195	$	195
USAC	45		—
Other	89		14
Total accounts payable to related companies:	$	329	$	209



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


15.	REPORTABLE SEGMENTS

Our financial statements currently reflect the following reportable segments, which conduct their business in the United States, as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

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

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales, refined product sales and gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in other.

We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments. Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership's proportionate ownership.

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The following tables present financial information by segment:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	761		$	699		$	1,578		$	1,467
Intersegment revenues	52			54			110			102
	813			753			1,688			1,569
Interstate transportation and storage:
Revenues from external customers	323			201			636			432
Intersegment revenues	5			6			8			10
	328			207			644			442
Midstream:
Revenues from external customers	594			633			1,034			1,198
Intersegment revenues	1,280			982			2,454			2,054
	1,874			1,615			3,488			3,252
NGL and refined products transportation and services:
Revenues from external customers	2,472			1,767			4,930			3,885
Intersegment revenues	96			12			184			160
	2,568			1,779			5,114			4,045
Crude oil transportation and services:
Revenues from external customers	4,789			2,460			8,520			5,035
Intersegment revenues	14			5			28			5
	4,803			2,465			8,548			5,040
All other:
Revenues from external customers	471			816			992			1,454
Intersegment revenues	31			54			81			186
	502			870			1,073			1,640
Eliminations	(1,478		)	(1,113		)	(2,865		)	(2,517		)
Total revenues	$	9,410		$	6,576		$	17,690		$	13,471

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	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017*			2018			2017*
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	208		$	148		$	400		$	317
Interstate transportation and storage	330			262			653			527
Midstream	414			412			791			732
NGL and refined products transportation and services	461			388			912			769
Crude oil transportation and services	548			228			1,012			415
All other	90			107			164			230
Total	2,051			1,545			3,932			2,990
Depreciation, depletion and amortization	(588		)	(557		)	(1,191		)	(1,117		)
Interest expense, net	(358		)	(336		)	(704		)	(668		)
Gain on Sunoco LP common unit repurchase	—			—			172			—
Loss on deconsolidation of CDM	(86		)	—			(86		)	—
Gains (losses) on interest rate derivatives	20			(25		)	72			(20		)
Non-cash compensation expense	(21		)	(15		)	(41		)	(38		)
Unrealized gains (losses) on commodity risk management activities	(265		)	34			(352		)	98
Adjusted EBITDA related to unconsolidated affiliates	(228		)	(247		)	(413		)	(486		)
Equity in earnings (losses) of unconsolidated affiliates	106			(61		)	34			12
Other, net	40			37			87			52
Income before income tax expense	$	671		$	375		$	1,510		$	823

* As adjusted. See Note 1.



	June 30, 2018		December 31, 2017
Assets:
Intrastate transportation and storage	$	5,604	$	5,020
Interstate transportation and storage	14,037		13,518
Midstream	19,949		20,004
NGL and refined products transportation and services	17,517		17,600
Crude oil transportation and services	18,168		17,736
All other	3,295		4,087
Total assets	$	78,570	$	77,965


16.	CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

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

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting.

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



	June 30, 2018
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—	$	—		$	494	$	—		$	494
All other current assets	—		57			8,527		(2,531		)	6,053
Property, plant and equipment, net	—		—			59,776		—			59,776
Investments in unconsolidated affiliates	51,199		12,078			3,636		(63,277		)	3,636
All other assets	8		—			8,603		—			8,611
Total assets	$	51,207	$	12,135		$	81,036	$	(65,808	)	$	78,570

Current liabilities	$	390	$	(3,571	)	$	12,353	$	(2,531	)	$	6,641
Non-current liabilities	22,949		7,606			7,338		—			37,893
Noncontrolling interest	—		—			6,171		—			6,171
Total partners’ capital	27,868		8,100			55,174		(63,277		)	27,865
Total liabilities and equity	$	51,207	$	12,135		$	81,036	$	(65,808	)	$	78,570



	December 31, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	(3	)	$	309	$	—		$	306
All other current assets	—			159			6,063		—			6,222
Property, plant and equipment, net	—			—			58,437		—			58,437
Investments in unconsolidated affiliates	48,378			11,648			3,816		(60,026		)	3,816
All other assets	—			—			9,184		—			9,184
Total assets	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

Current liabilities	$	(1,496	)	$	(3,660	)	$	12,150	$	—		$	6,994
Non-current liabilities	21,604			7,607			7,609		—			36,820
Noncontrolling interest	—			—			5,882		—			5,882
Total partners’ capital	28,270			7,857			52,168		(60,026		)	28,269
Total liabilities and equity	$	48,378		$	11,804		$	77,809	$	(60,026	)	$	77,965

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	Three Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	9,410		$	—		$	9,410
Operating costs, expenses, and other	—			—			8,467			—			8,467
Operating income	—			—			943			—			943
Interest expense, net	(289		)	(41		)	(28		)	—			(358		)
Equity in earnings of unconsolidated affiliates	701			66			106			(767		)	106
Gains on interest rate derivatives	20			—			—			—			20
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Other, net	—			—			46			—			46
Income before income tax expense	432			25			981			(767		)	671
Income tax expense	—			—			69			—			69
Net income	432			25			912			(767		)	602
Less: Net income attributable to noncontrolling interest	—			—			170			—			170
Net income attributable to partners	$	432		$	25		$	742		$	(767	)	$	432

Other comprehensive income	$	—		$	—		$	2		$	—		$	2
Comprehensive income	432			25			914			(767		)	604
Comprehensive income attributable to noncontrolling interest	—			—			170			—			170
Comprehensive income attributable to partners	$	432		$	25		$	744		$	(767	)	$	434



	Three Months Ended June 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	6,576		$	—		$	6,576
Operating costs, expenses, and other	—		1			5,839			—			5,840
Operating income (loss)	—		(1		)	737			—			736
Interest expense, net	—		(39		)	(297		)	—			(336		)
Equity in earnings (losses) of unconsolidated affiliates	199		137			(61		)	(336		)	(61		)
Losses on interest rate derivatives	—		—			(25		)	—			(25		)
Other, net	—		3			59			(1		)	61
Income before income tax expense	199		100			413			(337		)	375
Income tax expense	—		—			79			—			79
Net income	199		100			334			(337		)	296
Less: Net income attributable to noncontrolling interest	—		—			94			—			94
Net income attributable to partners	$	199	$	100		$	240		$	(337	)	$	202

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	199		100			333			(337		)	295
Comprehensive income attributable to noncontrolling interest	—		—			94			—			94
Comprehensive income attributable to partners	$	199	$	100		$	239		$	(337	)	$	201

* As adjusted. See Note 1.

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	Six Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—		$	—		$	17,690		$	—		$	17,690
Operating costs, expenses, and other	—			—			15,774			—			15,774
Operating income	—			—			1,916			—			1,916
Interest expense, net	(567		)	(82		)	(55		)	—			(704		)
Equity in earnings of unconsolidated affiliates	1,642			326			34			(1,968		)	34
Gains on interest rate derivatives	72			—			—			—			72
Gain on Sunoco LP unit repurchase	—			—			172			—			172
Loss on deconsolidation of CDM	—			—			(86		)	—			(86		)
Other, net	—			—			106			—			106
Income before income tax expense	1,147			244			2,087			(1,968		)	1,510
Income tax expense	—			—			29			—			29
Net income	1,147			244			2,058			(1,968		)	1,481
Less: Net income attributable to noncontrolling interest	—			—			334			—			334
Net income attributable to partners	$	1,147		$	244		$	1,724		$	(1,968	)	$	1,147

Other comprehensive income	$	—		$	—		$	3		$	—		$	3
Comprehensive income	1,147			244			2,061			(1,968		)	1,484
Comprehensive income attributable to noncontrolling interest	—			—			334			—			334
Comprehensive income attributable to partners	$	1,147		$	244		$	1,727		$	(1,968	)	$	1,150



	Six Months Ended June 30, 2017*
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	13,471		$	—		$	13,471
Operating costs, expenses, and other	—		1			12,051			—			12,052
Operating income (loss)	—		(1		)	1,420			—			1,419
Interest expense, net	—		(81		)	(587		)	—			(668		)
Equity in earnings of unconsolidated affiliates	1,010		765			12			(1,775		)	12
Losses on interest rate derivatives	—		—			(20		)	—			(20		)
Other, net	—		3			78			(1		)	80
Income before income tax expense	1,010		686			903			(1,776		)	823
Income tax expense	—		—			134			—			134
Net income	1,010		686			769			(1,776		)	689
Less: Net income attributable to noncontrolling interest	—		—			156			—			156
Net income attributable to partners	$	1,010	$	686		$	613		$	(1,776	)	$	533

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	1,010		686			768			(1,776		)	688
Comprehensive income attributable to noncontrolling interest	—		—			156			—			156
Comprehensive income attributable to partners	$	1,010	$	686		$	612		$	(1,776	)	$	532

* As adjusted. See Note 1.

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	Six Months Ended June 30, 2018
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	3,252		$	102		$	585		$	(989	)	$	2,950
Cash flows used in investing activities	(2,925		)	(99		)	(903		)	2,336			(1,591		)
Cash flows provided by (used in) financing activities	(327		)	—			503			(1,347		)	(1,171		)
Change in cash	—			3			185			—			188
Cash at beginning of period	—			(3		)	309			—			306
Cash at end of period	$	—		$	—		$	494		$	—		$	494



	Six Months Ended June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	1,010		$	652		$	1,764		$	(1,776	)	$	1,650
Cash flows used in investing activities	(716		)	(421		)	(2,125		)	1,776			(1,486		)
Cash flows provided by (used in) financing activities	(294		)	(249		)	291			—			(252		)
Change in cash	—			(18		)	(70		)	—			(88		)
Cash at beginning of period	—			41			319			—			360
Cash at end of period	$	—		$	23		$	249		$	—		$	272

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

AND RESULTS OF OPERATIONS

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

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

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

OVERVIEW

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


•	Natural gas operations, including the following:


•	natural gas midstream and intrastate transportation and storage; and


•	interstate natural gas transportation and storage.


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

RECENT DEVELOPMENTS

ETE and ETP Simplification Transaction

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.

Series D Preferred Units Issuance

ETP Senior Notes Offering and Redemption

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

Old Ocean Joint Venture Formation

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

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Acquisition of HPC

Series C Preferred Units Issuance

CDM Contribution

New Ethane Export Facility Joint Venture

In March 2018, ETP and Satellite Petrochemical USA Corp. (“Satellite”) entered into definitive agreements to form a joint venture, Orbit Gulf Coast NGL Exports, LLC (“Orbit”), with the purpose of constructing a new export terminal on the United States Gulf Coast to provide ethane to Satellite for consumption at their ethane cracking facilities in China. At the terminal, Orbit will construct an 800 MBbls refrigerated ethane storage tank, a 175 MBbls/d ethane refrigeration facility and a 20-inch ethane pipeline originating at ETP’s Mont Belvieu Fractionators that will make deliveries to the terminal as well as domestic markets in the region. ETP will be the operator of the Orbit assets, provide storage and marketing services for Satellite and provide Satellite with approximately 150 MBbls/d of ethane under a long-term, demand-based agreement. Additionally, ETP will construct and wholly own the infrastructure that is required to both supply ethane to the pipeline and to load the ethane on to very large ethane carriers destined for Satellite’s newly constructed ethane crackers in China’s Jiangsu Province. Subject to Chinese Governmental approval, it is anticipated that the Orbit export terminal will be ready for commercial service in the fourth quarter of 2020.

Sunoco LP Common Unit Repurchase

Regulatory Update

Interstate Natural Gas Transportation Regulation

Effective December 22, 2017, the 2017 Tax and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement because it is non-binding policy and parties will have the opportunity to address the policy as applied in future cases. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled

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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.

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

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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

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section below titled “Segment Operating Results.” Total Segment Adjusted EBITDA, as presented below, is equal to the consolidated measure of Adjusted EBITDA, which is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures. Our definition of total or consolidated Adjusted EBITDA is consistent with the definition of Segment Adjusted EBITDA above.

As discussed in Note 1 of the Partnership’s consolidated financial statements included in “Item 1. Financial Statements,” during the fourth quarter 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:
Intrastate transportation and storage	$	208		$	148		$	60		$	400		$	317		$	83
Interstate transportation and storage	330			262			68			653			527			126
Midstream	414			412			2			791			732			59
NGL and refined products transportation and services	461			388			73			912			769			143
Crude oil transportation and services	548			228			320			1,012			415			597
All other	90			107			(17		)	164			230			(66		)
Total	2,051			1,545			506			3,932			2,990			942
Depreciation, depletion and amortization	(588		)	(557		)	(31		)	(1,191		)	(1,117		)	(74		)
Interest expense, net	(358		)	(336		)	(22		)	(704		)	(668		)	(36		)
Gain on Sunoco LP common unit repurchase	—			—			—			172			—			172
Loss on deconsolidation of CDM	(86		)	—			(86		)	(86		)	—			(86		)
Gains (losses) on interest rate derivatives	20			(25		)	45			72			(20		)	92
Non-cash compensation expense	(21		)	(15		)	(6		)	(41		)	(38		)	(3		)
Unrealized gains (losses) on commodity risk management activities	(265		)	34			(299		)	(352		)	98			(450		)
Adjusted EBITDA related to unconsolidated affiliates	(228		)	(247		)	19			(413		)	(486		)	73
Equity in earnings (losses) of unconsolidated affiliates	106			(61		)	167			34			12			22
Other, net	40			37			3			87			52			35
Income before income tax expense	671			375			296			1,510			823			687
Income tax expense	(69		)	(79		)	10			(29		)	(134		)	105
Net income	$	602		$	296		$	306		$	1,481		$	689		$	792

* As adjusted.

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased for the three and six months ended June 30, 2018 compared to the same period last year primarily due to additional depreciation from assets recently placed in service. These increases were partially offset by the deconsolidation of CDM in April 2018, which reduced depreciation and amortization expense by $41 million for the three and six months ended June 30, 2018 compared to the prior periods.

Interest Expense, net. Interest expense, net of capitalized interest, increased for the three and six months ended June 30, 2018 compared to the same period last year primarily attributable to increases in long-term debt from ETP senior note issuances, partially offset by a decrease in credit facility borrowings and an increase in capitalized interest of $15 million and $36 million, respectively, for the three and six months ended June 30, 2018 compared to the prior periods.

Gain on Sunoco LP Common Unit Repurchase. In connection with Sunoco LP’s repurchase of its common units in February 2018, the Partnership recognized a gain of $172 million.

Loss on Deconsolidation of CDM. In connection with the CDM Contribution in April 2018, the Partnership deconsolidated CDM and recognized a loss of $86 million.

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Gains (Losses) on Interest Rate Derivatives. Gains on interest rate derivatives during the three and six months ended June 30, 2018 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 “Segment Operating Results” below.

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

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

Income Tax Expense. For the three and six months ended June 30, 2018 compared to the same period last year, income tax expense decreased primarily due to the decrease in federal corporate income tax rate per the Tax Act as well as $3 million and $70 million, respectively, of deferred tax benefit adjustments during the three and six months ended June 30, 2018 as the result of a state statutory rate reduction.

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Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	33		$	30		$	3		$	60		$	51		$	9
FEP	13			13			—			27			25			2
MEP	8			10			(2		)	17			20			(3		)
Sunoco LP	16			(110		)	126			(135		)	(124		)	(11		)
USAC	(2		)	—			(2		)	(2		)	—			(2		)
Other	38			(4		)	42			67			40			27
Total equity in earnings (losses) of unconsolidated affiliates	$	106		$	(61	)	$	167		$	34		$	12		$	22

Adjusted EBITDA related to unconsolidated affiliates⁽¹⁾:
Citrus	$	85		$	88		$	(3	)	$	160		$	163		$	(3	)
FEP	18			19			(1		)	37			37			—
MEP	20			21			(1		)	42			43			(1		)
Sunoco LP	39			83			(44		)	68			137			(69		)
USAC	21			—			21			21			—			21
Other	45			36			9			85			106			(21		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	228		$	247		$	(19	)	$	413		$	486		$	(73	)

Distributions received from unconsolidated affiliates:
Citrus	$	27		$	22		$	5		$	73		$	63		$	10
FEP	15			10			5			32			10			22
MEP	18			20			(2		)	31			93			(62		)
Sunoco LP	22			37			(15		)	58			72			(14		)
USAC	10			—			10			10			—			10
Other	21			30			(9		)	42			53			(11		)
Total distributions received from unconsolidated affiliates	$	113		$	119		$	(6	)	$	246		$	291		$	(45	)


⁽¹⁾	These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

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


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

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


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


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

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization.

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

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
Intrastate transportation and storage	$	267		$	202	$	438		$	384
Interstate transportation and storage	328			207		644			$	442
Midstream	593			571		1,146			1,084
NGL and refined products transportation and services	587			516		1,187			1,075
Crude oil transportation and services	442			374		1,010			646
All other	57			76		152			178
Intersegment eliminations	(4		)	6		(15		)	(12		)
Total segment margin	2,270			1,952		4,562			3,797

Less:
Operating expenses	627			539		1,231			1,031
Depreciation, depletion and amortization	588			557		1,191			1,117
Selling, general and administrative	112			120		224			230
Operating income	$	943		$	736	$	1,916		$	1,419

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Intrastate Transportation and Storage



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Natural gas transported (BBtu/d)	10,327			9,261			1,066			9,802			8,569			1,233
Withdrawals from storage natural gas inventory (BBtu)	—			—			—			17,703			23,093			(5,390		)
Revenues	$	813		$	753		$	60		$	1,688		$	1,569		$	119
Cost of products sold	546			551			(5		)	1,250			1,185			65
Segment margin	267			202			65			438			384			54
Unrealized (gains) losses on commodity risk management activities	(8		)	(21		)	13			45			(6		)	51
Operating expenses, excluding non-cash compensation expense	(51		)	(46		)	(5		)	(90		)	(84		)	(6		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(7		)	(5		)	(2		)	(13		)	(11		)	(2		)
Adjusted EBITDA related to unconsolidated affiliates	7			18			(11		)	20			34			(14		)
Segment Adjusted EBITDA	$	208		$	148		$	60		$	400		$	317		$	83

Volumes. For the three and six months ended June 30, 2018 compared to the same period last year, transported volumes increased primarily due to favorable market pricing. In addition, beginning in April 2018, transported volumes also reflected RIGS as a consolidated subsidiary, as discussed in “Recent Developments” above.

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



	Three Months Ended June 30,							Six Months Ended June 30,
	2018		2017		Change			2018			2017		Change
Transportation fees	$	134	$	104	$	30		$	251		$	228	$	23
Natural gas sales and other (excluding unrealized gains and losses)	108		61		47			199			94		105
Retained fuel revenues (excluding unrealized gains and losses)	13		15		(2		)	26			28		(2		)
Storage margin (excluding unrealized gains and losses)	4		1		3			7			28		(21		)
Unrealized gains (losses) on commodity risk management activities	8		21		(13		)	(45		)	6		(51		)
Total segment margin	$	267	$	202	$	65		$	438		$	384	$	54

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


•	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, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $26 million, $6 million and $2 million, respectively, and a decrease of $13 million in Adjusted EBITDA related to unconsolidated affiliates;


•	an increase of $4 million in transportation fees, excluding the incremental transportation fees related to the RIGS consolidation discussed above, primarily due to higher demand on existing pipelines; and

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•	an increase of $3 million in realized storage margin primarily due to higher realized derivative gains; partially offset by


•	a decrease of $2 million in retained fuel revenues as a result of lower natural gas pricing.

Segment Adjusted EBITDA. For the six months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:


•	an increase of $105 million in realized natural gas sales and other 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, as discussed in “Recent Developments” above, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $26 million, $6 million and $2 million, respectively, and a decrease of $15 million in Adjusted EBITDA related to unconsolidated affiliates; 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.

Interstate Transportation and Storage



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Natural gas transported (BBtu/d)	8,707			5,299			3,408			8,457			5,476			2,981
Natural gas sold (BBtu/d)	17			17			—			17			17			—
Revenues	$	328		$	207		$	121		$	644		$	442		$	202
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(105		)	(67		)	(38		)	(199		)	(141		)	(58		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(17		)	(7		)	(10		)	(34		)	(19		)	(15		)
Adjusted EBITDA related to unconsolidated affiliates	123			128			(5		)	239			243			(4		)
Other	1			1			—			3			2			1
Segment Adjusted EBITDA	$	330		$	262		$	68		$	653		$	527		$	126

Volumes. For the three months ended June 30, 2018 compared to the same period last year, transported volumes reflected an increase of 1,748 BBtu/d as a result of the partial in service of the Rover pipeline; increases of 654 BBtu/d and 425 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to increased utilization of higher contracted capacity; an increase of 350 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into intrastate markets; and an increase of 200 BBtu/d on the Transwestern pipeline resulting from favorable opportunities in the midcontinent and Waha areas from the Permian supply basin.

For the six months ended June 30, 2018 compared to the same period last year, transported volumes reflected an increase of 1,610 BBtu/d as a result of the partial in service of the Rover pipeline; increases of 529 BBtu/d and 328 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to higher demand resulting from colder weather and increased utilization by the Rover pipeline; an increase of 397 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale and deliveries into intrastate markets; and an increase of 141 BBtu/d on the Transwestern pipeline resulting from favorable market opportunities in the midcontinent and Waha areas from the Permian supply basin.

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


•	an increase of $68 million from the partial in service of the Rover pipeline with increases of $105 million in revenues, $30 million in operating expenses and $7 million in selling, general and administrative expenses; and

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•	an aggregate increase of $19 million in revenues, excluding the incremental revenue related to the Rover pipeline in service discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines, partially offset by $3 million of lower revenues on the Tiger pipeline due to a customer contract restructuring; partially offset by


•	an increase of $8 million in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs;


•	an increase of $3 million in selling, general and administrative expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to a reimbursement of legal fees and a franchise tax settlement received in 2017; and


•	a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower sales of short-term firm capacity on Citrus.

Segment Adjusted EBITDA. For the six months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:


•	An increase of $117 million from the partial in service of the Rover pipeline with increases of $187 million in revenues, $56 million in operating expenses and $14 million in selling, general and administrative expenses; and


•	an aggregate increase of $21 million in revenues, excluding the incremental revenues related to the Rover pipeline in service discussed above, 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


•	an increase of $2 million in operating expenses, excluding the incremental expenses related to the Rover pipeline in service discussed above, primarily due to higher maintenance project costs; 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.

Midstream



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Gathered volumes (BBtu/d)	11,576			10,961			615			11,442			10,599			843
NGLs produced (MBbls/d)	513			474			39			508			459			49
Equity NGLs (MBbls/d)	31			28			3			30			27			3
Revenues	$	1,874		$	1,615		$	259		$	3,488		$	3,252		$	236
Cost of products sold	1,281			1,044			237			2,342			2,168			174
Segment margin	593			571			22			1,146			1,084			62
Unrealized gains on commodity risk management activities	—			(3		)	3			—			(19		)	19
Operating expenses, excluding non-cash compensation expense	(169		)	(152		)	(17		)	(333		)	(313		)	(20		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(20		)	(11		)	(9		)	(40		)	(34		)	(6		)
Adjusted EBITDA related to unconsolidated affiliates	9			7			2			16			14			2
Other	1			—			1			2			—			2
Segment Adjusted EBITDA	$	414		$	412		$	2		$	791		$	732		$	59

Volumes. For the three and six months ended June 30, 2018 compared to the same periods last year, gathered volumes and NGL production increased primarily due to increases in the Permian and Northeast regions, partially offset by smaller declines in other regions.

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



	Three Months Ended June 30,							Six Months Ended June 30,
	2018		2017		Change			2018		2017		Change
Gathering and processing fee-based revenues	$	453	$	436	$	17		$	874	$	844	$	30
Non-fee-based contracts and processing (excluding unrealized gains and losses)	140		132		8			272		221		51
Unrealized gains on commodity risk management activities	—		3		(3		)	—		19		(19		)
Total segment margin	$	593	$	571	$	22		$	1,146	$	1,084	$	62

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:


•	an increase of $17 million in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and midcontinent/Panhandle regions;


•	an increase of $6 million in non-fee-based margin primarily due to higher crude oil and NGL prices;


•	an increase of $2 million in non-fee-based margin due to increased throughput volume in the Permian region; 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 $17 million in operating expenses primarily due to increases of $6 million in outside services, $5 million in materials, $2 million in employee costs and $2 million in ad valorem taxes; 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.

Segment Adjusted EBITDA. For the six months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:


•	an increase of $27 million in non-fee-based margin primarily due to higher crude oil and NGL prices;


•	an increase of $24 million in non-fee-based margin due to increased throughput volume in the Permian region;


•	an increase of $30 million in fee-based margin due to growth in the Permian and Northeast regions, offset by declines in the South Texas, North Texas and 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 due to increases of $8 million in outside services, $5 million in materials, $4 million in employee costs and $3 million in ad valorem taxes; 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.

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NGL and Refined Products Transportation and Services



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
NGL transportation volumes (MBbls/d)	967			835			132			951			823			128
Refined products transportation volumes (MBbls/d)	637			643			(6		)	629			633			(4		)
NGL and refined products terminal volumes (MBbls/d)	789			767			22			746			779			(33		)
NGL fractionation volumes (MBbls/d)	473			431			42			473			430			43
Revenues	$	2,568		$	1,779		$	789		$	5,114		$	4,045		$	1,069
Cost of products sold	1,981			1,263			718			3,927			2,970			957
Segment margin	587			516			71			1,187			1,075			112
Unrealized (gains) losses on commodity risk management activities	13			(4		)	17			—			(54		)	54
Operating expenses, excluding non-cash compensation expense	(141		)	(125		)	(16		)	(280		)	(252		)	(28		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(17		)	(17		)	—			(35		)	(36		)	1
Adjusted EBITDA related to unconsolidated affiliates	19			18			1			40			35			5
Other	—			—			—			—			1			(1		)
Segment Adjusted EBITDA	$	461		$	388		$	73		$	912		$	769		$	143

Volumes. For the three and six months ended June 30, 2018 compared to the same periods last year, NGL transportation volumes increased primarily from the Permian region resulting from a ramp up in production from existing customers.

Refined products transportation volumes decreased slightly for the three and six months ended June 30, 2018 compared to the same periods last year primarily due to lower throughput volumes from the Midwest region due to end user operational issues, partially offset by increased throughput volumes from the Southwest region due to increased demand.

Compared to the same periods last year, NGL and refined products terminal volumes increased for the three months ended June 30, 2018 but decreased for the six months ended June 30, 2018. The increase for the three months ended June 30, 2018 compared to the same period last year was primarily due to more volumes loaded at our Nederland terminal as propane export demand increased, as well as higher refined products throughput volumes at our Eagle Point terminal, partially offset by lower throughput volumes at our Marcus Hook Industrial Complex primarily due to Mariner East 1 system downtime during the second quarter of 2018. For the six months ended June 30, 2018 compared to the same period in the prior year, the decrease was primarily due to lower throughput volumes at our Marcus Hook Industrial Complex due to Mariner East 1 system downtime, lower refined product throughput volumes at our Eagle Point terminal and lower volumes at our refined products marketing terminals.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the three and six months ended June 30, 2018 compared to the same periods last year primarily due to increased volumes from Permian producers.

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



	Three Months Ended June 30,								Six Months Ended June 30,
	2018			2017		Change			2018		2017		Change
Fractionators and Refinery services margin	$	128		$	117	$	11		$	262	$	237	$	25
Transportation margin	290			241		49			556		474		82
Storage margin	48			53		(5		)	104		110		(6		)
Terminal Services margin	91			81		10			185		168		17
Marketing margin	43			20		23			80		32		48
Unrealized gains (losses) on commodity risk management activities	(13		)	4		(17		)	—		54		(54		)
Total segment margin	$	587		$	516	$	71		$	1,187	$	1,075	$	112

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

•

an increase of $49 million in transportation margin due to a $43 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, an $11 million increase resulting from a reclassification between our transportation and fractionation margins, a $4 million increase due to higher throughput on Mariner West and a $2 million increase on Mariner South primarily due to system downtime in the prior period. These increases were partially offset by an $11 million decrease resulting from 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 our butane blending operations, a $9 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a $4 million increase from optimizing sales of purity product from our 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 our Mont Belvieu fractionation facility, a $6 million increase from blending gains as a result of improved market pricing and a $2 million increase from Mariner South as more cargoes were loaded at Mariner South. These increases were partially offset by an $11 million decrease resulting from a reclassification between our transportation and fractionation margins; and

•

an increase of $10 million in terminal services margin due to a $7 million increase 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 a $5 million increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a $2 million decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex; partially offset by

•

an increase of $16 million in operating expenses primarily due to a $7 million increase 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, a $4 million increase in utilities and ad valorem taxes on the fractionators, and a $3 million increase in overhead costs; and


•	a decrease of $5 million in storage margin primarily due to the expiration and amendments to various NGL and refined products storage contracts.

Segment Adjusted EBITDA. For the six months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

•

an increase of $82 million in transportation margin due to $78 million from increased producer volumes from the Permian region on our Texas NGL pipelines, an $11 million increase due to higher throughput on Mariner West driven by end user facility constraints in the prior period, an $11 million increase resulting from a reclassification between our transportation and fractionation margins, a $3 million increase on Mariner South primarily due to system downtime in the prior period and a $4 million increase from higher deficiency fees. These increases were partially offset by a $17 million decrease resulting

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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 our butane blending operations, a $17 million increase from sales of domestic propane and other products at our Marcus Hook Industrial Complex and a $13 million increase from optimizing sales of purity product from our Mont Belvieu fractionators;

•

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 our Mont Belvieu fractionation facility, a $9 million increase from blending gains as a result of improved market pricing and a $4 million increase as we loaded more cargoes at our Mariner South export facility. These increases were partially offset by an $11 million decrease resulting from a reclassification between our transportation and fractionation margins;

•

an increase of $17 million in terminal services margin due to a $18 million increase 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 a $6 million increase at our Nederland terminal due to increased demand for propane exports. These increases were partially offset by a $4 million decrease due to the effect of Mariner East pipeline system downtime on our Marcus Hook Industrial Complex and a $3 million decrease from our marketing terminal volumes primarily due to the sale of one of our terminals in April 2017; and


•	an increase of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to improved contributions from our unconsolidated refined products joint venture interests; partially offset by

•

an increase of $28 million in operating expenses due to a $18 million increase 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, a $6 million increases in certain allocated overhead and a $4 million increase in utilities and ad valorem taxes on the fractionators; and

•

a decrease of $6 million in storage margin due to a $8 million decrease from the expiration and amendments to various NGL and refined products storage contracts and a $4 million decrease from the expiration of a fixed fee transport agreement in 2017. These increases were partially offset by a $6 million increase from throughput fees collected at our Mont Belvieu storage terminal and increased demand on the Explorer Pipeline.

Crude Oil Transportation and Services



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Crude transportation volumes (MBbls/d)	4,242			3,452			790			4,036			3,248			788
Crude terminals volumes (MBbls/d)	2,103			1,950			153			2,022			1,864			158
Revenues	$	4,803		$	2,465		$	2,338		$	8,548		$	5,040		$	3,508
Cost of products sold	4,361			2,091			2,270			7,538			4,394			3,144
Segment margin	442			374			68			1,010			646			364
Unrealized losses (gains) on commodity risk management activities	262			(2		)	264			305			(2		)	307
Operating expenses, excluding non-cash compensation expense	(144		)	(114		)	(30		)	(271		)	(186		)	(85		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(20		)	(32		)	12			(42		)	(49		)	7
Adjusted EBITDA related to unconsolidated affiliates	8			2			6			10			6			4
Segment Adjusted EBITDA	$	548		$	228		$	320		$	1,012		$	415		$	597

Volumes. For the three and six months ended June 30, 2018 crude transportation volumes increased due to placing the Bakken pipeline in service in June 2017 as well as increased volumes on existing pipelines due to increased production in West Texas. For the three and six months ended June 30, 2018 crude terminal volumes increased due to increased volumes delivered to our Nederland crude terminal from the Bakken pipeline and from increased West Texas production.

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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 our crude oil transportation and services segment increased due to the net impacts of the following:

•

an increase of $332 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $193 million increase resulting primarily from placing our 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 our 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 our Nederland facility as a result of increased exports;


•	a decrease of $12 million in selling, general and administrative expenses 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 our joint ventures; partially offset by

•

an increase of $30 million in operating expenses due to a $13 million increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $3 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $14 million increase from existing transportation assets due to increases of $7 million in utilities, $5 million in expense projects, $5 million in ad valorem taxes and $5 million in management fees, partially offset by decreases in environmental fees of $5 million and capacity leases of $3 million.

Segment Adjusted EBITDA. For the six months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

•

an increase of $671 million in segment margin (excluding unrealized losses on commodity risk management activities) due to a $417 million increase resulting primarily from placing our 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 our 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 our 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 due to a $13 million decrease in professional fees, partially offset by an increase of $6 million related to Bakken insurance and management fees; and


•	an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to a new contract at one of our joint ventures; partially offset by

•

an increase of $85 million in operating expenses due to a $39 million increase primarily resulting from placing our Bakken pipeline in service in the second quarter of 2017; a $15 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $31 million increase from existing transportation assets due to increases of $10 million in ad valorem taxes, $9 million in management fees, $8 million in utilities, $5 million in expense projects and $5 million in freight, partially offset by decreases in environmental fees of $5 million and capacity leases of $1 million.

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All Other



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Revenues	$	502		$	870		$	(368	)	$	1,073		$	1,640		$	(567	)
Cost of products sold	445			794			(349		)	921			1,462			(541		)
Segment margin	57			76			(19		)	152			178			(26		)
Unrealized (gains) losses on commodity risk management activities	(2		)	(4		)	2			2			(17		)	19
Operating expenses, excluding non-cash compensation expense	(10		)	(31		)	21			(41		)	(52		)	11
Selling, general and administrative expenses, excluding non-cash compensation expense	(19		)	(27		)	8			(37		)	(48		)	11
Adjusted EBITDA related to unconsolidated affiliates	62			76			(14		)	88			156			(68		)
Other and eliminations	2			17			(15		)	—			13			(13		)
Segment Adjusted EBITDA	$	90		$	107		$	(17	)	$	164		$	230		$	(66	)

Amounts reflected in our all other segment primarily include:

•

our equity method investment in limited partnership units of Sunoco LP consisting of 26.2 million and 43.5 million Sunoco LP common units, representing 31.8% and 43.7% of Sunoco LP’s total outstanding common units as of June 30, 2018 and June 30, 2017, respectively. 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;


•	our natural gas marketing and compression operations. Subsequent to our contribution of CDM to USAC in April 2018, our all other segment includes our equity method investment in USAC consisting of 19.2 million USAC common units and 6.4 million USAC Class B Units, together representing 26.6% of the limited partner interests;


•	a non-controlling interest in PES, comprising 33% of PES’ outstanding common units; and


•	our investment in coal handling facilities.

Segment Adjusted EBITDA. For the three months ended June 30, 2018 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:


•	a decrease of $44 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’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 investment in USAC held by ETP subsequent to the CDM Contribution; partially offset by


•	a decrease of $14 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 $12 million in Adjusted EBITDA related to unconsolidated affiliates from our 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 our all other segment decreased due to the net impacts of the following:


•	a decrease of $69 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in Sunoco LP resulting from the Partnership’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;

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•	a decrease of $18 million in Adjusted EBITDA related to unconsolidated affiliates primarily from our investment in PES; and


•	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.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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 management’s control.

We currently expect 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 our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

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

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

Cash Flows

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

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and net changes in operating assets and liabilities (net of effects of acquisitions and deconsolidations). Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for

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such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers.

Six months ended June 30, 2018 compared to six months ended June 30, 2017. Cash provided by operating activities during 2018 was $2.95 billion compared to $1.65 billion for 2017 and net income was $1.48 billion and $689 million for 2018 and 2017, respectively. The difference between net income and cash provided by operating activities for the six months ended June 30, 2018 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and deconsolidations) of $229 million and other non-cash items totaling $1.04 billion.

The non-cash activity in 2018 and 2017 consisted primarily of depreciation, depletion and amortization of $1.19 billion and $1.12 billion, respectively, and non-cash compensation expense of $41 million and $38 million, respectively. Unconsolidated affiliate activity in 2018 and 2017 consisted of equity in earnings of $34 million and $12 million, respectively, and distributions received of $215 million and $197 million, respectively. Non-cash activity in 2018 also included a gain on the sale of Sunoco LP units of $172 million, a loss on the deconsolidation of CDM of $86 million and an increase in deferred income taxes of $52 million. Non-cash activity in 2017 also included an increase in deferred income taxes of $121 million.

Cash paid for interest, net of interest capitalized, was $690 million and $673 million for the six months ended June 30, 2018 and 2017, respectively.

Capitalized interest was $160 million and $124 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, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Six months ended June 30, 2018 compared to six months ended June 30, 2017. Cash used in investing activities during 2018 was $1.59 billion compared to $1.49 billion in 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 $3.35 billion compared to $2.83 billion for 2017. Additional detail related to our capital expenditures is provided in the table below. During 2018, we received $1.23 billion in cash related to the CDM Contribution and $540 million in cash related to the Sunoco LP common unit repurchase. During 2017, we received $2.00 billion in cash related to the Bakken equity sale to MarEn Bakken Company, paid $280 million in cash for the acquisition of PennTex noncontrolling interest and paid $261 million in cash for all other acquisitions.

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



	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Intrastate transportation and storage	$	195	$	21	$	216
Interstate transportation and storage	351		37		388
Midstream	448		65		513
NGL and refined products transportation and services	974		26		1,000
Crude oil transportation and services	205		21		226
All other (including eliminations)	68		34		102
Total capital expenditures	$	2,241	$	204	$	2,445

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures.

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Six months ended June 30, 2018 compared to six months ended June 30, 2017. Cash used in financing activities during 2018 was $1.17 billion compared to $252 million for 2017. In 2018 and 2017, we received net proceeds from common unit offerings of $39 million and $990 million, respectively. In 2018 we received $436 million from preferred unit offerings. During 2018, we had a net increase in our debt level of $458 million compared to a net increase of $258 million for 2017. We have paid distributions of $2.01 billion to our unitholders in 2018 compared to $1.70 billion in 2017. We have also paid distributions of $359 million to noncontrolling interests in 2018 compared to $186 million in 2017. In addition, we have received capital contributions of $318 million in cash from noncontrolling interests in 2018 compared to $456 million in 2017. During 2018, we also repurchased common units for cash of $24 million and incurred debt issuance costs of $38 million. During 2017, we also repurchased our outstanding Legacy ETP Preferred Units for cash of $53 million and incurred debt issuance costs of $20 million.

Off-Balance Sheet Arrangements

Guarantee of Sunoco LP Notes


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


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


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

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	June 30, 2018			December 31, 2017
ETP Senior Notes ⁽¹⁾⁽²⁾	$	29,354		$	27,005
Transwestern Senior Notes	575			575
Panhandle Senior Notes	386			785
Credit facilities and commercial paper:
ETP $4.00 billion Revolving Credit Facility due December 2022 ⁽³⁾	1,228			2,292
ETP $1.00 billion 364-Day Credit Facility due November 2018	—			50
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			2,500
Other long-term debt	4			5
Unamortized premiums, net of discounts and fair value adjustments	39			61
Deferred debt issuance costs	(190		)	(179		)
Total debt	33,896			33,094
Less: current maturities of long-term debt	155			407
Long-term debt, less current maturities	$	33,741		$	32,687


⁽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 in June 2018, see “ETP Senior Notes Offering and Redemption” below.


⁽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.

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.

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

Credit Facilities and Commercial Paper

ETP Five-Year Credit Facility

ETP 364-Day Facility

Bakken Credit Facility

Covenants Related to Our Credit Agreements

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

CASH DISTRIBUTIONS

Distributions on common units declared and/or paid by the Partnership 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 preferred units declared and/or paid by the Partnership subsequent to December 31, 2017 were as follows:



Period Ended	Record Date	Payment Date	Rate
Series A Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	15.451
June 30, 2018	August 1, 2018	August 15, 2018	31.250
Series B Preferred Units
December 31, 2017	February 1, 2018	February 15, 2018	$	16.378
June 30, 2018	August 1, 2018	August 15, 2018	33.125
Series C Preferred Units
June 30, 2018	August 1, 2018	August 15, 2018	$	0.56337

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



	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		)
Series A Preferred Units	30			—
Series B Preferred Units	18			—
Series C Preferred Units	10			—
Total distributions declared to partners	$	2,191		$	1,648

In connection with previous transactions, ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods:



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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2017 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 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		3			—		48,510		2			1
Options – Puts	(3,043	)	—			—		13,000		—			—
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		(50		)	18		4,650		(13		)	4
Swing Swaps IFERC	52,413		(1		)	—		87,253		(2		)	1
Fixed Swaps/Futures	5,360		(2		)	3		(4,700	)	(1		)	2
Forward Physical Contracts	(174,465	)	4			—		(145,105	)	6			41
NGL (MBbls) – Forwards/Swaps	(1,590	)	(16		)	11		(2,493	)	5			16
Crude (MBbls) – Forwards/Swaps	44,190		(307		)	261		9,172		(4		)	9
Refined Products (MBbls) – Futures	(1,076	)	(5		)	5		(3,783	)	(25		)	4
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.

Interest Rate Risk

As of June 30, 2018, we had $4.33 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $43 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

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interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

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



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


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


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

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 the $1.50 billion of interest rate swaps whereby we pay a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $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 Chief Executive Officer (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of 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

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)–15(f) or Rule 15d–15(f) of the Exchange Act) during the three months ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

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ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Annual Report on Form 10-K filed with the SEC on February 23, 2018 and Note 11 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Partners, 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 related to 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.

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;

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•	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.

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

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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 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 2/3% 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.

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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 1.5 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 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;

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•	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.

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

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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.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended June 30, 2018, the Partnership issued 1,261,221 ETP Common Units to settle contingent consideration related to a previous acquisition. These securities are exempt from registration under Section 4(a)(2) of the Securities Act of 1933.

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ITEM 6. EXHIBITS

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



Exhibit Number		Description
2.1		Contribution Agreement, dated as of January 15, 2018, by and among USA Compression Partners, LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC, and solely for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed January 16, 2018)
2.2		Purchase Agreement, dated as of January 15, 2018, by and among USA Compression Holdings, LLC, Energy Transfer Equity, L.P., Energy Transfer Partners, L.L.C., and solely for certain purposes therein R/C IV USACP Holdings, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed January 16, 2018)
2.3		Agreement and Plan of Merger, dated as of August 1, 2018, by and among LE GP, LLC, Energy Transfer Equity, L.P., Streamline Merger Sub, LLC, Energy Transfer Partners, L.L.C. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 to the Form 8-K filed August 3, 2018)
3.1		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1 Registration Statement filed October 22, 2001)
3.2		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed September 1, 2015)
3.3		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed April 28, 2017)
3.4		Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K filed April 28, 2017)
3.5		Amendment No. 1, dated November 16, 2017, to the Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated as of April 28, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed November 16, 2017)
3.6		Amendment No. 2, dated as of April 25, 2018, to Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated as of April 28, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed April 25, 2018)
3.7		Amendment No. 3, dated July 23, 2018, to Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated as of April 28, 2017 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed July 23, 2018)
4.1		Indenture, dated as of June 8, 2018, among Energy Transfer Partners, L.P. as issuer, Sunoco Logistics Partners Operations L.P., as guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed June 8, 2018)
4.2		First Supplemental Indenture dated as of June 8, 2018 by and among Energy Transfer Partners, L.P., as issuer, the subsidiary guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed June 8, 2018)
4.3		Forms of Notes (included in Exhibit 4.2 hereto, incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed June 8, 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		Transition Services Agreement, dated as of April 2, 2018, by and among USA Compression Partners, LP, CDM Resource Management LLC, CDM Environmental & Technical Services LLC and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed April 3, 2018)
10.3***		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 Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document



*		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 PARTNERS, L.P.

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

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

Date:	August 9, 2018	By:	/s/ A. Troy Sturrock
			A. Troy Sturrock
			Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)