Energy Transfer Operating, L.P. - FORM 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2017



¨	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 4, 2017, the registrant had 1,099,625,923 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	38

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	55

ITEM 4. CONTROLS AND PROCEDURES	57

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	58

ITEM 1A. RISK FACTORS	58

ITEM 6. EXHIBITS	59

SIGNATURE	60

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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, 2016 filed with the Securities and Exchange Commission on February 24, 2017 and Exhibit 99.3 to the Partnership’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 8, 2017.

Definitions

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



	/d		per day

	AmeriGas		AmeriGas Partners, L.P.

	AOCI		accumulated other comprehensive income (loss)

	AROs		asset retirement obligations

	Bbls		barrels

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

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

	Citrus		Citrus, LLC

	CrossCountry		CrossCountry Energy, LLC

	DOJ		U.S. Department of Justice

	ETC Compression		ETC Compression, LLC

	EPA		Environmental Protection Agency

	ETC FEP		ETC Fayetteville Express Pipeline, LLC

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

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

	ETC Tiger		ETC Tiger Pipeline, LLC

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

	ET Interstate		Energy Transfer Interstate Holdings, LLC

	ET Rover		ET Rover Pipeline LLC

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

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

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

	IDRs		incentive distribution rights

	Lake Charles LNG		Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC), a subsidiary of ETE

	LIBOR		London Interbank Offered Rate

	MEP		Midcontinent Express Pipeline LLC

	MBbls		thousand barrels

	MMBtu		million British thermal units

	MMcf		million cubic feet

	MTBE		methyl tertiary butyl ether

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

	NYMEX		New York Mercantile Exchange

	OSHA		federal Occupational Safety and Health Act

	OTC		over-the-counter

	Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries

	PCBs		polychlorinated biphenyls

	PennTex		PennTex Midstream Partners, LP

	PES		Philadelphia Energy Solutions, a refining joint venture

	Preferred Units		ETP Series A cumulative convertible preferred units

	Regency		Regency Energy Partners LP

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

	Sea Robin		Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle

	SEC		Securities and Exchange Commission

	Sunoco Logistics		Sunoco Logistics Partners L.P.

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC, a subsidiary of Panhandle

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). 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, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	272		$	360
Accounts receivable, net	2,914			3,002
Accounts receivable from related companies	364			209
Inventories	1,520			1,712
Income taxes receivable	148			128
Derivative assets	8			20
Other current assets	160			298
Total current assets	5,386			5,729

Property, plant and equipment	62,790			58,220
Accumulated depreciation and depletion	(8,254		)	(7,303		)
	54,536			50,917

Advances to and investments in unconsolidated affiliates	4,228			4,280
Other non-current assets, net	707			672
Intangible assets, net	5,443			4,696
Goodwill	3,919			3,897
Total assets	$	74,219		$	70,191

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, 2017		December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,900	$	2,900
Accounts payable to related companies	200		43
Derivative liabilities	7		166
Accrued and other current liabilities	2,517		1,905
Current maturities of long-term debt	1,365		1,189
Total current liabilities	6,989		6,203

Long-term debt, less current maturities	32,029		31,741
Long-term notes payable – related company	—		250
Non-current derivative liabilities	201		76
Deferred income taxes	4,498		4,394
Other non-current liabilities	1,066		952

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

Equity:
General Partner	220		206
Limited Partners:
Common Unitholders	25,389		14,946
Class H Unitholder	—		3,480
Class I Unitholder	—		2
Accumulated other comprehensive income	7		8
Total partners’ capital	25,616		18,642
Noncontrolling interest	3,799		7,885
Total equity	29,415		26,527
Total liabilities and equity	$	74,219	$	70,191

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,
	2017			2016			2017			2016
REVENUES:
Natural gas sales	$	1,022		$	695		$	2,034		$	1,533
NGL sales	1,485			1,150			3,032			2,090
Crude sales	2,131			1,713			4,478			2,923
Gathering, transportation and other fees	1,067			1,045			2,091			2,005
Refined product sales	304			234			775			479
Other	567			452			1,061			740
Total revenues	6,576			5,289			13,471			9,770
COSTS AND EXPENSES:
Cost of products sold	4,742			3,630			9,934			6,598
Operating expenses	425			374			804			722
Depreciation, depletion and amortization	557			496			1,117			966
Selling, general and administrative	120			74			230			155
Total costs and expenses	5,844			4,574			12,085			8,441
OPERATING INCOME	732			715			1,386			1,329
OTHER INCOME (EXPENSE):
Interest expense, net	(346		)	(317		)	(685		)	(636		)
Equity in earnings (losses) of unconsolidated affiliates	(61		)	119			12			195
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Other, net	71			27			97			44
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	371			463			790			781
Income tax expense (benefit)	79			(9		)	134			(67		)
NET INCOME	292			472			656			848
Less: Net income attributable to noncontrolling interest	93			102			133			167
NET INCOME ATTRIBUTABLE TO PARTNERS	199			370			523			681
General Partner’s interest in net income	251			223			457			520
Class H Unitholder’s interest in net income	—			85			98			164
Class I Unitholder’s interest in net income	—			2			—			4
Common Unitholders’ interest in net income (loss)	$	(52	)	$	60		$	(32	)	$	(7	)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$	(0.04	)	$	0.07		$	(0.04	)	$	(0.03	)
Diluted	$	(0.04	)	$	0.06		$	(0.04	)	$	(0.03	)

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,
	2017			2016			2017			2016
Net income	$	292		$	472		$	656		$	848
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	1			3			3			5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	(1		)	6			(3		)	(3		)
Foreign currency translation adjustments	—			—			—			(1		)
Change in other comprehensive income from unconsolidated affiliates	(1		)	(5		)	(1		)	(11		)
	(1		)	4			(1		)	(10		)
Comprehensive income	291			476			655			838
Less: Comprehensive income attributable to noncontrolling interest	93			102			133			167
Comprehensive income attributable to partners	$	198		$	374		$	522		$	671

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, 2017

(Dollars in millions)

(unaudited)



				Limited Partners
	General Partner			Common Units			Class H Units			Class I Units			Accumulated Other Comprehensive Income			Noncontrolling Interest			Total
Balance, December 31, 2016	$	206		$	14,946		$	3,480		$	2		$	8		$	7,885		$	26,527
Distributions to partners	(443		)	(1,162		)	(95		)	(2		)	—			—			(1,702		)
Distributions to noncontrolling interest	—			—			—			—			—			(186		)	(186		)
Units issued for cash	—			990			—			—			—			—			990
Sunoco Logistics Merger	—			9,459			(3,483		)	—			—			(5,976		)	—
Capital contributions from noncontrolling interest	—			—			—			—			—			1,444			1,444
Sale of Bakken Pipeline interest	—			1,260			—			—			—			740			2,000
Acquisition of PennTex noncontrolling interest	—			(48		)	—			—			—			(232		)	(280		)
Other comprehensive income, net of tax	—			—			—			—			(1		)	—			(1		)
Other, net	—			(24		)	—			—			—			(9		)	(33		)
Net income	457			(32		)	98			—			—			133			656
Balance, June 30, 2017	$	220		$	25,389		$	—		$	—		$	7		$	3,799		$	29,415

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,
	2017			2016
OPERATING ACTIVITIES
Net income	$	656		$	848
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,117			966
Deferred income taxes	121			(79		)
Amortization included in interest expense	(2		)	(12		)
Inventory valuation adjustments	56			(106		)
Unit-based compensation expense	38			38
Distributions on unvested awards	(15		)	(13		)
Equity in earnings of unconsolidated affiliates	(12		)	(195		)
Distributions from unconsolidated affiliates	197			199
Other non-cash	(96		)	(124		)
Net change in operating assets and liabilities, net of effects of acquisition	(410		)	(96		)
Net cash provided by operating activities	1,650			1,426
INVESTING ACTIVITIES
Proceeds from Bakken Pipeline Transaction	2,000			—
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction	—			2,200
Cash paid for acquisition of PennTex noncontrolling interest	(280		)	—
Cash paid for all other acquisitions	(261		)	—
Capital expenditures, excluding allowance for equity funds used during construction	(2,842		)	(3,479		)
Contributions in aid of construction costs	10			25
Contributions to unconsolidated affiliates	(225		)	(31		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	94			56
Proceeds from the sale of assets	25			7
Change in restricted cash	—			(2		)
Other	(7		)	(1		)
Net cash used in investing activities	(1,486		)	(1,225		)
FINANCING ACTIVITIES
Proceeds from borrowings	11,466			7,811
Repayments of long-term debt	(10,953		)	(7,514		)
Cash (paid) received from affiliate notes	(255		)	147
Units issued for cash	990			408
Subsidiary units issued for cash	—			667
Capital contributions from noncontrolling interest	456			161
Distributions to partners	(1,702		)	(1,813		)
Distributions to noncontrolling interest	(186		)	(209		)
Redemption of Preferred Units	(53		)	—
Debt issuance costs	(20		)	—
Other	5			—
Net cash used in financing activities	(252		)	(342		)
Decrease in cash and cash equivalents	(88		)	(141		)
Cash and cash equivalents, beginning of period	360			527
Cash and cash equivalents, end of period	$	272		$	386

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”, formerly named “Sunoco Logistics Partners L.P.”, as discussed below) is a consolidated subsidiary of ETE.

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.

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


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


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


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

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

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

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

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

•

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

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•	ET Interstate, with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:


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


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


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


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


•	ETC MEP, which directly owns a 50% interest in MEP.


•	ET Rover, which owns a 65% interest in Rover pipeline.


•	ETC Compression, LLC, engaged in natural gas compression services and related equipment sales.

•

ETP Holdco, which indirectly owns Panhandle and Sunoco, Inc. Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. Sunoco, Inc. owned and operated retail marketing assets, which were contributed to Sunoco LP in March 2016. Subsequent to this transaction, Sunoco Inc.’s assets primarily consist of its ownership in Retail Holdings, which owns noncontrolling interests in Sunoco LP and PES. Subsequent to the Sunoco Logistics Merger, ETLP holds an equity method investment in ETP through ETP Holdco’s ownership of ETP Class E, Class G, and Class K units, which investment is eliminated in the consolidated financial statements.


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

Subsequent to the Sunoco Logistics Merger, our financial statements reflect the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

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

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements of Energy Transfer Partners, L.P. for the year ended December 31, 2016, included in Exhibit 99.3 to the Partnership’s Current Report on Form 8-K filed on May 8, 2017. 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.

Certain prior period amounts have been reclassified to conform to the current year presentation. These reclassifications had no impact on net income or total equity.

Use of Estimates

The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although

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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

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.

In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catchup transition method). The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method.

We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.

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

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

In October 2016, the FASB issued Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.

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

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15,

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2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.


2.	ACQUISITIONS AND CONTRIBUTION TRANSACTIONS

Permian Express Partners

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

The Partnership’s ownership percentage in PEP was approximately 85% at June 30, 2017. In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in its ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.


3.	CASH AND CASH EQUIVALENTS

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

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

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



	Six Months Ended June 30,
	2017			2016
Accounts receivable	$	88		$	(471	)
Accounts receivable from related companies	(115		)	(129		)
Inventories	137			(157		)
Other current assets	77			(53		)
Other non-current assets, net	(39		)	8
Accounts payable	(286		)	509
Accounts payable to related companies	131			21
Accrued and other current liabilities	(389		)	(22		)
Other non-current liabilities	7			20
Derivative assets and liabilities, net	(21		)	178
Net change in operating assets and liabilities, net of effects of acquisitions	$	(410	)	$	(96	)

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Non-cash investing and financing activities are as follows:



	Six Months Ended June 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,363	$	861
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	—		194
Net gains from subsidiary common unit issuances	—		14
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—


4.	INVENTORIES

Inventories consisted of the following:



	June 30, 2017		December 31, 2016
Natural gas and NGLs	$	546	$	699
Crude oil	681		683
Refined products	76		113
Spare parts and other	217		217
Total inventories	$	1,520	$	1,712

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


5.	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, 2017 was $34.68 billion and $33.39 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations was $33.85 billion and $32.93 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, 2017, 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, 2017 and December 31, 2016 based on inputs used to derive their fair values:



				Fair Value Measurements at June 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	9		$	9		$	—
Swing Swaps IFERC	3			1			2
Fixed Swaps/Futures	38			38			—
Forward Physical Swaps	4			—			4
Power:
Forwards	13			—			13
Futures	1			1			—
Natural Gas Liquids – Forwards/Swaps	77			77			—
Crude – Futures	9			9			—
Total commodity derivatives	154			135			19
Total assets	$	154		$	135		$	19
Liabilities:
Interest rate derivatives	$	(201	)	$	—		$	(201	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(9		)	(9		)	—
Swing Swaps IFERC	(2		)	—			(2		)
Fixed Swaps/Futures	(25		)	(25		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(12		)	—			(12		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(70		)	(70		)	—
Refined Products – Futures	(3		)	(3		)	—
Crude – Futures	(5		)	(5		)	—
Total commodity derivatives	(128		)	(113		)	(15		)
Total liabilities	$	(329	)	$	(113	)	$	(216	)

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				Fair Value Measurements at December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	14		$	14		$	—		$	—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Swaps	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options – Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	233			233			—			—
Refined Products – Futures	1			1			—			—
Crude – Futures	9			9			—			—
Total commodity derivatives	362			355			7			—
Total assets	$	362		$	355		$	7		$	—
Liabilities:
Interest rate derivatives	$	(193	)	$	—		$	(193	)	$	—
Embedded derivatives in Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(11		)	(11		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(149		)	(149		)	—			—
Power:
Forwards	(5		)	—			(5		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids – Forwards/Swaps	(273		)	(273		)	—			—
Refined Products – Futures	(17		)	(17		)	—			—
Crude – Futures	(13		)	(13		)	—			—
Total commodity derivatives	(472		)	(464		)	(8		)	—
Total liabilities	$	(666	)	$	(464	)	$	(201	)	$	(1	)


6.	NET INCOME (LOSS) PER LIMITED PARTNER UNIT

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

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Net income	$	292		$	472		$	656		$	848
Less: Income attributable to noncontrolling interest	93			102			133			167
Net income, net of noncontrolling interest	199			370			523			681
General Partner’s interest in net income	251			223			457			520
Class H Unitholder’s interest in net income	—			85			98			164
Class I Unitholder’s interest in net income	—			2			—			4
Common Unitholders’ interest in net income (loss)	(52		)	60			(32		)	(7		)
Additional (earnings) losses allocated to General Partner	15			(3		)	12			(6		)
Distributions on employee unit awards, net of allocation to General Partner	(6		)	(5		)	(13		)	(10		)
Net income (loss) available to Common Unitholders	$	(43	)	$	52		$	(33	)	$	(23	)
Weighted average Common Units – basic ⁽¹⁾	1,021.7			752.4			922.5			743.9
Basic net income (loss) per Common Unit	$	(0.04	)	$	0.07		$	(0.04	)	$	(0.03	)

Net income (loss) available to Common Unitholders	$	(43	)	$	52		$	(33	)	$	(23	)
Income attributable to Preferred Units	—			(4		)	—			(3		)
Diluted net income (loss) available to Common Unitholders	$	(43	)	$	48		$	(33	)	$	(26	)
Weighted average Common Units – basic ⁽¹⁾	1,021.7			752.4			922.5			743.9
Dilutive effect of unvested employee unit awards	—			1.0			—			—
Dilutive effect of Preferred Units	—			0.5			—			0.5
Weighted average Common Units – diluted ⁽¹⁾	1,021.7			753.9			922.5			744.4
Diluted net income (loss) per Common Unit	$	(0.04	)	$	0.06		$	(0.04	)	$	(0.03	)

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

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


7.	DEBT OBLIGATIONS

Credit Facilities and Commercial Paper

ETLP Credit Facility

The ETLP Credit Facility allows for borrowings of up to $3.75 billion and matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of June 30, 2017, the ETLP Credit Facility had $1.54 billion of outstanding borrowings, all of which was commercial paper.

Sunoco Logistics Credit Facilities

ETP maintains the Sunoco Logistics $2.50 billion unsecured revolving credit facility (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of June 30, 2017, the Sunoco Logistics Credit Facility had $1.67 billion of outstanding borrowings, which included $241 million of commercial paper.

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

Bakken Credit Facility

In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provides substantially all of the remaining capital necessary to complete the projects. As of June 30, 2017, $2.50 billion was outstanding under this credit facility.

PennTex Revolving Credit Facility

PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). As of June 30, 2017, the PennTex Revolving Credit Facility had $148 million of outstanding borrowings. In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

Compliance with Our Covenants

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


8.	PREFERRED UNITS

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


9.	EQUITY

The changes in outstanding common units during the six months ended June 30, 2017 were as follows:



		Number of Units
Number of common units at December 31, 2016 ⁽¹⁾		794.8
Common units issued in connection with equity distribution agreements		15.6
Common units issued in connection with the distribution reinvestment plan		2.8
Common units issued to ETE in a private placement transaction		23.7
Common unit increase from Sunoco Logistics Merger ⁽²⁾		255.4
Issuance of common units under equity incentive plans		0.3
Number of common units at June 30, 2017		1,092.6


⁽¹⁾	The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.


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

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion. During the six months ended June 30, 2017, the Partnership received proceeds of $358 million, net of $4 million of commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. During the six months ended June 30, 2017, distributions of $71 million were reinvested under the distribution reinvestment plan. In July 2017, the Partnership initiated a new distribution reinvestment plan.

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Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which the Partnership indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, the Partnership owns a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.

PennTex Tender Offer and Limited Call Right Exercise

In June 2017, Energy Transfer Partners, L.P. purchased all of the outstanding PennTex common units not previously owned by Energy Transfer Partners, L.P. for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.

Quarterly Distributions of Available Cash

Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the Partnership's limited partnership agreement, which was Sunoco Logistics' limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end 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.

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

The following table shows the target distribution levels and distribution “splits” between the general partner and the holders of the Partnership’s common units:



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

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

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

Following are distributions declared and/or paid by the Partnership subsequent to the Sunoco Logistics Merger:



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

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



	Total Year
2017 (remainder)	$	336
2018	153
2019	128
Each year beyond 2019	33

Accumulated Other Comprehensive Income

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



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


10.	INCOME TAXES

For the three and six months ended June 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $77 million during the periods presented. For the three and six months ended June 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.


11.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Residual Support Agreement – AmeriGas

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

Guarantee of Sunoco LP Notes

In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC.

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.

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Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

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,
	2017		2016		2017		2016
Rental expense	$	19	$	21	$	39	$	39

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.

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

During the summer of 2016, individuals affiliated with or sympathetic to the Standing Rock Sioux Tribe (the “SRST”) began to protest the development of the pipeline project. Protesters trespassed on to the construction site, tampered with equipment, and disrupted construction activity at the site. In response to the protests, Dakota Access filed a lawsuit in federal court in North Dakota to restrain protestors from disrupting construction and also requested a temporary restraining order (“TRO”) against the Chairman of the SRST and the protestors. The U.S. District Court granted and later dissolved a TRO enjoining protest activity. The protestors moved to dismiss the lawsuit and the Court granted their motion in May 2017.

On July 25, 2016, the U.S. Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the SRST filed a lawsuit in the U.S. District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.

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

The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then

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

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four tribes.

On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. The USACE has advised the Court that it expects to have completed this additional work by the end of 2017. The Court ordered briefing that will conclude at the end of August 2017 to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process and the Court is expected to rule on this issue during September 2017. The USACE and Dakota Access have each filed a brief with the Court to oppose any shutdown of operations of the pipeline during this review process. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relating to its remand order.

While we believe that the pending lawsuits are unlikely to block operation of the pipeline, we cannot assure this outcome. We 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 (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.

MTBE Litigation

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

Fact discovery has concluded with respect to an initial set of 9 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. The initial set of 9 New Jersey trial sites are now pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. The remaining

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portion of the New Jersey case remains in the multidistrict litigation. In early 2017, Sunoco, Inc. and Sunoco, Inc. (R&M) and two other co-defendants reached a settlement in principle with the State of New Jersey, subject to the parties agreeing on the terms and conditions of a Settlement and Release agreement, among other things. 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 said 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

Following the January 26, 2015 announcement of the Regency merger, purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to 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 on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware. The lawsuit 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. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court issued an order reversing the judgment of the Court of Chancery that dismissed Counts I and II of Dieckman’s Complaint. On February 21, 2017, Regency and the other defendants filed their respective Motions to Dismiss the Chancery Court matter. 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. Briefing on both of these motions is ongoing.

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

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and 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 intends to file a petition for review with the Texas Supreme Court.

Sunoco Logistics Merger Litigation

Five purported Energy Transfer Partners, L.P. common unitholders (“Plaintiffs”) separately filed seven putative unitholder class action lawsuits challenging the merger and the disclosures made in connection with the merger. The lawsuits are styled (a) Shure v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00044-UNA, in the United States District Court for the District of Delaware (the “Shure Lawsuit”); (b) Verlin v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00045-UNA, in the United States District Court for the District of Delaware (the “Verlin Lawsuit”); (c) Duany v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00058-UNA, in the United States District Court for the District of Delaware (the “Duany Lawsuit”); (d) Epstein v. Energy Transfer Partners, L.P. et. al., Case No, 1:17-cv-00069, in the United States District Court for the District of Delaware (the “Epstein Lawsuit”) and (e) Sgnilek v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00141, in the United States District Court for the District of Delaware (the “Sgnilek Lawsuit” and collectively with the Shure Lawsuit, Verlin Lawsuit, Duany Lawsuit, and Epstein Lawsuit, the “Lawsuits”).

Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. Plaintiffs allege that (i) defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the ETP Board have violated Section 20(a) of the Exchange Act. Plaintiffs in the Shure Lawsuit and Verlin Lawsuit also allege that Sunoco Logistics has violated Section 20(a) of the Exchange Act. Plaintiffs also assert, in general, that the terms of the merger (including, among other terms, the merger consideration) are unfair to ETP common unitholders and resulted from an unfair and conflicted process. Based on these allegations, the Sgnilek Lawsuit alleges that (a) the ETP Board, ETP GP, ETP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Partners LLC have aided and abetted those alleged breaches.

Based on these allegations, Plaintiffs seek to enjoin defendants from proceeding with or consummating the merger unless and until defendants disclose the allegedly omitted information summarized above. The Sgnilek Lawsuit also seeks to enjoin defendants from proceeding with or consummating the merger unless and until the ETP Board adopts and implements processes to obtain the best possible terms for ETP common unitholders. To the extent that the merger is consummated before injunctive

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relief is granted, Plaintiffs seek to have the merger rescinded. Plaintiffs also seek damages and reimbursement of attorneys’ fees.

On May 31, 2017, a Joint Stipulation and Order was filed (1) setting deadlines for Plaintiffs’ Amended Complaint and Defendants’ Answer; (2) dismissing Sunoco Logistics and Sunoco Partners LLC from the lawsuits; and (3) consolidating the remaining five lawsuits under the Shure Lawsuit.

Defendants believe the Lawsuits are without merit and intend to defend vigorously against the Lawsuits and any other actions challenging the merger.

Litigation filed by BP Products

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

SPLP filed an answer on June 1, 2015, denying the allegations in the complaint. SPLP asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). By order dated July 31, 2015, FERC set the matter for hearing.

On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued her Initial Decision and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC trial staff challenged various aspects of the initial decision related to remedies and the statute of limitations issue.

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, 2017 and December 31, 2016, accruals of approximately $71 million and $77 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.

In December 2016, Sunoco Logistics received multiple NOVs from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016. Sunoco Logistics also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC. These actions propose penalties in excess of $0.1 million, and ETP is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these

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matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.

The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of ETP subsidiary Rover Pipeline LLC’s (“Rover”) pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of more than $900,000 in connection with the alleged violations and is seeking certain corrective actions. ETP is working with Ohio EPA to resolve the matter. The timing or outcome of this matter cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. The timing or outcome of this matter cannot be reasonably determined at this time; however, Rover anticipates resuming HDD activities before their suspension results in a material delay of pipeline construction.

On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover has 20 days to submit a corrective action plan and schedule for agency review. The order follows several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order, has already addressed many of the stormwater control issues, and anticipates having the corrective action plan and schedule in place before the order results in a material delay of pipeline construction.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania. On August 1st 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.

In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with Sunoco Pipeline regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania that affected waters of the State. 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. The company is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.

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

Environmental Matters

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

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Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, 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. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.

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 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.


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


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

•

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of June 30, 2017, Sunoco, Inc. had been named as a PRP at approximately 49 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.

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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, 2017		December 31, 2016
Current	$	38	$	26
Non-current	276		283
Total environmental liabilities	$	314	$	309

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, 2017 and 2016, Sunoco, Inc. recorded $8 million and $8 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2017 and 2016, Sunoco, Inc. recorded $10 million and $14 million, respectively, of expenditures related to environmental cleanup programs.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, 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 operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s 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.	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.

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

We use derivatives in our NGL and refined products transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

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

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

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The following table details our outstanding commodity-related derivatives:



	June 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	465,000		2017	(682,500	)	2017
Basis Swaps IFERC/NYMEX⁽¹⁾	33,112,500		2017	2,242,500		2017
Options – Puts	11,500,000		2018	—		—
Power (Megawatt):
Forwards	497,530		2017-2018	391,880		2017-2018
Futures	(212,880	)	2017-2018	109,564		2017-2018
Options – Puts	(364,000	)	2017	(50,400	)	2017
Options – Calls	607,200		2017	186,400		2017
Crude (Bbls) – Futures	(1,569,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,630,000	)	2017-2018	10,750,000		2017-2018
Swing Swaps IFERC	39,900,000		2017	(5,662,500	)	2017
Fixed Swaps/Futures	(39,250,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(9,302,540	)	2017	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(4,501,400	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(803,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(32,440,000	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(32,440,000	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	32,440,000		2017	36,370,000		2017


⁽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, 2017		December 31, 2016
July 2017⁽²⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% 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, 2017		December 31, 2016		June 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	8	$	—	$	(1	)	$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	127		338		(109		)	(416		)
Commodity derivatives	19		24		(18		)	(52		)
Interest rate derivatives	—		—		(201		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	146		362		(328		)	(662		)
Total derivatives	$	154	$	362	$	(329	)	$	(666	)

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, 2017			December 31, 2016			June 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(201	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	19			24			(18		)	(52		)
Broker cleared derivative contracts	Other current assets	135			338			(110		)	(420		)
Total gross derivatives		154			362			(329		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(11		)	(4		)	11			4
Payments on margin deposit	Other current assets	(110		)	(338		)	110			338
Total net derivatives		$	33		$	20		$	(208	)	$	(324	)

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

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



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2017		2016		2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	6	$	21	$	2	$	17
Total		$	6	$	21	$	2	$	17



	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,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	15		$	(7	)	$	26		$	(16	)
Commodity derivatives – Non-trading	Cost of products sold	7			(48		)	(3		)	(43		)
Interest rate derivatives	Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Embedded derivatives	Other, net	—			(4		)	1			(4		)
Total		$	(3	)	$	(140	)	$	4		$	(214	)


13.	RELATED PARTY TRANSACTIONS

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

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

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Affiliated revenues	$	133	$	133	$	251	$	207

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



	June 30, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	—	$	22
Sunoco LP	179		96
PES	8		6
FGT	9		15
Lake Charles LNG	1		4
Trans-Pecos Pipeline, LLC	4		1
Comanche Trail Pipeline, LLC	1		—
Traverse Rover LLC	100		—
Other	62		65
Total accounts receivable from related companies:	$	364	$	209

Accounts payable to related companies:
Sunoco LP	$	177	$	20
FGT	—		1
Lake Charles LNG	2		3
Other	21		19
Total accounts payable to related companies:	$	200	$	43



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


14.	REPORTABLE SEGMENTS

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

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services; and

•all other.

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

The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from Energy Transfer Partners, L.P. to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from Energy Transfer Partners, L.P. to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of June 30, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units,

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representing 43.7% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.

Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

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 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 (excluding lower of cost or market 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,
	2017			2016			2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	699		$	428		$	1,467		$	874
Intersegment revenues	54			113			102			225
	753			541			1,569			1,099
Interstate transportation and storage:
Revenues from external customers	201			229			432			483
Intersegment revenues	6			5			10			10
	207			234			442			493
Midstream:
Revenues from external customers	633			690			1,198			1,217
Intersegment revenues	982			640			2,054			1,205
	1,615			1,330			3,252			2,422
NGL and refined products transportation and services:
Revenues from external customers	1,767			1,445			3,885			2,617
Intersegment revenues	1			42			160			203
	1,768			1,487			4,045			2,820
Crude oil transportation and services:
Revenues from external customers	2,460			1,904			5,035			3,290
Intersegment revenues	126			85			240			164
	2,586			1,989			5,275			3,454
All other:
Revenues from external customers	816			593			1,454			1,289
Intersegment revenues	54			118			186			276
	870			711			1,640			1,565
Eliminations	(1,223		)	(1,003		)	(2,752		)	(2,083		)
Total revenues	$	6,576		$	5,289		$	13,471		$	9,770

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	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	148		$	149		$	317		$	328
Interstate transportation and storage	262			278			527			570
Midstream	412			298			732			561
NGL and refined products transportation and services	391			341			773			689
Crude oil transportation and services	279			124			434			352
All other	107			180			230			282
Total	1,599			1,370			3,013			2,782
Depreciation, depletion and amortization	(557		)	(496		)	(1,117		)	(966		)
Interest expense, net	(346		)	(317		)	(685		)	(636		)
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Non-cash unit-based compensation expense	(15		)	(19		)	(38		)	(38		)
Unrealized gains (losses) on commodity risk management activities	34			(18		)	98			(81		)
Inventory valuation adjustments	(58		)	132			(56		)	106
Adjusted EBITDA related to unconsolidated affiliates	(247		)	(252		)	(486		)	(471		)
Equity in earnings (losses) of unconsolidated affiliates	(61		)	119			12			195
Other, net	47			25			69			41
Income before income tax expense (benefit)	$	371		$	463		$	790		$	781



	June 30, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	7,129	$	5,164
Interstate transportation and storage	12,153		10,833
Midstream	17,240		17,873
NGL and refined products transportation and services	16,407		14,128
Crude oil transportation and services	16,137		15,941
All other	5,153		6,252
Total assets	$	74,219	$	70,191


15.	CONSOLIDATING GUARANTOR FINANCIAL INFORMATION

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

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

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



	June 30, 2017
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	23		$	249	$	—		$	272
All other current assets	—			—			5,114		—			5,114
Property, plant and equipment, net	—			—			54,536		—			54,536
Investments in unconsolidated affiliates	24,154			11,502			4,228		(35,656		)	4,228
All other assets	—			4			10,065		—			10,069
Total assets	$	24,154		$	11,529		$	74,192	$	(35,656	)	$	74,219

Current liabilities	$	(1,491	)	$	(3,421	)	$	11,901	$	—		$	6,989
Non-current liabilities	—			7,062			30,753		—			37,815
Noncontrolling interest	—			—			3,799		—			3,799
Total partners' capital	25,645			7,888			27,739		(35,656		)	25,616
Total liabilities and equity	$	24,154		$	11,529		$	74,192	$	(35,656	)	$	74,219



	December 31, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Eliminations			Consolidated Partnership
Cash and cash equivalents	$	—		$	41		$	319	$	—		$	360
All other current assets	—			2			5,367		—			5,369
Property, plant and equipment, net	—			—			50,917		—			50,917
Investments in unconsolidated affiliates	23,350			10,664			4,280		(34,014		)	4,280
All other assets	—			5			9,260		—			9,265
Total assets	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191

Current liabilities	$	(1,761	)	$	(3,800	)	$	11,764	$	—		$	6,203
Non-current liabilities	299			7,313			30,148		(299		)	37,461
Noncontrolling interest	—			—			1,297		—			1,297
Total partners' capital	24,812			7,199			26,934		(33,715		)	25,230
Total liabilities and equity	$	23,350		$	10,712		$	70,143	$	(34,014	)	$	70,191

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	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			5,843			—			5,844
Operating income (loss)	—		(1		)	733			—			732
Interest expense, net	—		(39		)	(307		)	—			(346		)
Equity in earnings (losses) of unconsolidated affiliates	199		137			(61		)	(336		)	(61		)
Losses on interest rate derivatives	—		—			(25		)	—			(25		)
Other, net	—		3			69			(1		)	71
Income before income tax expense	199		100			409			(337		)	371
Income tax expense	—		—			79			—			79
Net income	199		100			330			(337		)	292
Less: Net income attributable to noncontrolling interest	—		—			93			—			93
Net income attributable to partners	$	199	$	100		$	237		$	(337	)	$	199

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	199		100			329			(337		)	291
Comprehensive income attributable to noncontrolling interest	—		—			93			—			93
Comprehensive income attributable to partners	$	199	$	100		$	236		$	(337	)	$	198



	Three Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	5,289		$	—		$	5,289
Operating costs, expenses, and other	—		1			4,573			—			4,574
Operating income (loss)	—		(1		)	716			—			715
Interest expense, net	—		(39		)	(278		)	—			(317		)
Equity in earnings of unconsolidated affiliates	451		242			119			(693		)	119
Losses on interest rate derivatives	—		—			(81		)	—			(81		)
Other, net	—		—			27			—			27
Income before income tax benefit	451		202			503			(693		)	463
Income tax benefit	—		—			(9		)	—			(9		)
Net income	451		202			512			(693		)	472
Less: Net income attributable to noncontrolling interest	—		—			18			—			—
Net income attributable to partners	$	451	$	202		$	494		$	(693	)	$	472

Other comprehensive income	$	—	$	—		$	4		$	—		$	4
Comprehensive income	451		202			516			(693		)	476
Comprehensive income attributable to noncontrolling interest	—		—			18			—			18
Comprehensive income attributable to partners	$	451	$	202		$	498		$	(693	)	$	458

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	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			12,084			—			12,085
Operating income (loss)	—		(1		)	1,387			—			1,386
Interest expense, net	—		(81		)	(604		)	—			(685		)
Equity in earnings of unconsolidated affiliates	1,010		765			12			(1,775		)	12
Losses on interest rate derivatives	—		—			(20		)	—			(20		)
Other, net	—		3			95			(1		)	97
Income before income tax expense	1,010		686			870			(1,776		)	790
Income tax expense	—		—			134			—			134
Net income	1,010		686			736			(1,776		)	656
Less: Net income attributable to noncontrolling interest	—		—			133			—			133
Net income attributable to partners	$	1,010	$	686		$	603		$	(1,776	)	$	523

Other comprehensive loss	$	—	$	—		$	(1	)	$	—		$	(1	)
Comprehensive income	1,010		686			735			(1,776		)	655
Comprehensive income attributable to noncontrolling interest	—		—			133			—			133
Comprehensive income attributable to partners	$	1,010	$	686		$	602		$	(1,776	)	$	522



	Six Months Ended June 30, 2016
	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Revenues	$	—	$	—		$	9,770		$	—		$	9,770
Operating costs, expenses, and other	—		1			8,440			—			8,441
Operating income (loss)	—		(1		)	1,330			—			1,329
Interest expense, net	—		(77		)	(559		)	—			(636		)
Equity in earnings of unconsolidated affiliates	811		425			195			(1,236		)	195
Losses on interest rate derivatives	—		—			(151		)	—			(151		)
Other, net	—		—			44			—			44
Income before income tax benefit	811		347			859			(1,236		)	781
Income tax benefit	—		—			(67		)	—			(67		)
Net income	811		347			926			(1,236		)	848
Less: Net income attributable to noncontrolling interest	—		—			36			—			36
Net income attributable to partners	$	811	$	347		$	890		$	(1,236	)	$	812

Other comprehensive loss	$	—	$	—		$	(10	)	$	—		$	(10	)
Comprehensive income	811		347			916			(1,236		)	838
Comprehensive income attributable to noncontrolling interest	—		—			36			—			36
Comprehensive income attributable to partners	$	811	$	347		$	880		$	(1,236	)	$	802

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	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



	Six Months Ended June 30, 2016
	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Eliminations			Consolidated Partnership
Cash flows provided by operating activities	$	811		$	320		$	1,531		$	(1,236	)	$	1,426
Cash flows used in investing activities	(1,029		)	(847		)	(585		)	1,236			(1,225		)
Cash flows provided by (used in) financing activities	218			526			(1,086		)	—			(342		)
Change in cash	—			(1		)	(140		)	—			(141		)
Cash at beginning of period	—			37			490			—			527
Cash at end of period	$	—		$	36		$	350		$	—		$	386

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

AND RESULTS OF OPERATIONS

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

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in Exhibit 99.3 to the Partnership’s Current Report on Form 8-K filed with the SEC on May 8, 2017. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I – Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 24, 2017 and in Exhibit 99.3 to our Current Report on Form 8-K filed with the SEC on May 8, 2017.

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

OVERVIEW

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


•	Natural gas operations, including the following:


•	natural gas midstream and intrastate transportation and storage; and


•	interstate natural gas transportation and storage.


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

RECENT DEVELOPMENTS

Rover Contribution Agreement

In July 2017, ETP announced that it had entered into a contribution agreement, whereby the Partnership will receive approximately $1.57 billion in exchange for a 49.9% interest in the holding company that owns 65% of the Rover pipeline. The transaction is expected to close in October 2017, subject to customary closing conditions.

PennTex Tender Offer and Limited Call Right Exercise

Sunoco Logistics Merger

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

Permian Express Partners

The Partnership’s ownership percentage in PEP was approximately 85% as of June 30, 2017. In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in its ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is

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reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale

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.

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Consolidated Results



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	148		$	149		$	(1	)	$	317		$	328		$	(11	)
Interstate transportation and storage	262			278			(16		)	527			570			(43		)
Midstream	412			298			114			732			561			171
NGL and refined products transportation and services	391			341			50			773			689			84
Crude oil transportation and services	279			124			155			434			352			82
All other	107			180			(73		)	230			282			(52		)
Total	1,599			1,370			229			3,013			2,782			231
Depreciation, depletion and amortization	(557		)	(496		)	(61		)	(1,117		)	(966		)	(151		)
Interest expense, net	(346		)	(317		)	(29		)	(685		)	(636		)	(49		)
Losses on interest rate derivatives	(25		)	(81		)	56			(20		)	(151		)	131
Non-cash unit-based compensation expense	(15		)	(19		)	4			(38		)	(38		)	—
Unrealized gains (losses) on commodity risk management activities	34			(18		)	52			98			(81		)	179
Inventory valuation adjustments	(58		)	132			(190		)	(56		)	106			(162		)
Adjusted EBITDA related to unconsolidated affiliates	(247		)	(252		)	5			(486		)	(471		)	(15		)
Equity in earnings (losses) of unconsolidated affiliates	(61		)	119			(180		)	12			195			(183		)
Other, net	47			25			22			69			41			28
Income before income tax (expense) benefit	371			463			(92		)	790			781			9
Income tax (expense) benefit	(79		)	9			(88		)	(134		)	67			(201		)
Net income	$	292		$	472		$	(180	)	$	656		$	848		$	(192	)

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, 2017 compared to the same periods last year primarily due to additional depreciation from assets recently placed in service and recent acquisitions.

Interest Expense, net. Interest expense, net of capitalized interest, increased for the three and six months ended June 30, 2017 compared to the same periods last year primarily attributable to the Dakota Access and ETCO term loans that became effective in August 2016.

Losses on Interest Rate Derivatives. Losses on interest rate derivatives during the three and six months ended June 30, 2017 and 2016 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.

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

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

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.

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

Income Tax (Expense) Benefit. For the three and six months ended June 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $77 million during the periods presented. For the six months ended June 30, 2017, the total impact of statutory rate changes was $113 million, including the $77 million impact from the Sunoco Logistics Merger and statutory rate changes in the prior year. The remainder of the increase in income tax expense for the six months ended June 30, 2017 was primarily due to higher earnings among the Partnership’s consolidated corporate subsidiaries.

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,
	2017			2016		Change			2017			2016		Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	30		$	28	$	2		$	51		$	49	$	2
FEP	13			12		1			25			26		(1		)
PES	(20		)	7		(27		)	(6		)	1		(7		)
MEP	10			11		(1		)	20			22		(2		)
HPC	5			7		(2		)	12			15		(3		)
AmeriGas	(6		)	19		(25		)	3			17		(14		)
Sunoco LP	(110		)	23		(133		)	(124		)	38		(162		)
Other	17			12		5			31			27		4
Total equity in earnings (losses) of unconsolidated affiliates	$	(61	)	$	119	$	(180	)	$	12		$	195	$	(183	)

Adjusted EBITDA related to unconsolidated affiliates⁽¹⁾:
Citrus	$	88		$	87	$	1		$	163		$	161	$	2
FEP	19			18		1			37			37		—
PES	(10		)	17		(27		)	16			21		(5		)
MEP	21			23		(2		)	43			47		(4		)
HPC	12			15		(3		)	27			30		(3		)
Sunoco LP	83			68		15			137			125		12
Other	34			24		10			63			50		13
Total Adjusted EBITDA related to unconsolidated affiliates	$	247		$	252	$	(5	)	$	486		$	471	$	15

Distributions received from unconsolidated affiliates:
Citrus	$	22		$	27	$	(5	)	$	63		$	62	$	1
FEP	10			13		(3		)	10			30		(20		)
AmeriGas	3			3		—			6			6		—
MEP	20			18		2			93			39		54
HPC	13			13		—			13			25		(12		)
Sunoco LP	37			36		1			72			66		6
Other	14			10		4			34			27		7
Total distributions received from unconsolidated affiliates	$	119		$	120	$	(1	)	$	291		$	255	$	36

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⁽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.


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


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


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

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Margin 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.

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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,
	2017			2016			2017			2016
Segment Margin by segment:
Intrastate transportation and storage	$	202		$	188		$	384		$	353
Interstate transportation and storage	207			234			442			493
Midstream	571			460			1,084			874
NGL and refined products transportation and services	523			448			1,080			879
Crude oil transportation and services	369			319			614			586
All other	76			86			178			179
Intersegment eliminations	(114		)	(76		)	(245		)	(192		)
Total Segment Margin	1,834			1,659			3,537			3,172

Less:
Operating expenses	425			374			804			722
Depreciation, depletion and amortization	557			496			1,117			966
Selling, general and administrative	120			74			230			155
Operating income	$	732		$	715		$	1,386		$	1,329

Intrastate Transportation and Storage



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
Natural gas transported (MMBtu/d)	9,254,999			8,659,255			595,744			8,566,276			8,444,614			121,662
Revenues	$	753		$	541		$	212		$	1,569		$	1,099		$	470
Cost of products sold	551			353			198			1,185			746			439
Segment margin	202			188			14			384			353			31
Unrealized (gains) losses on commodity risk management activities	(21		)	(7		)	(14		)	(6		)	31			(37		)
Operating expenses, excluding non-cash compensation expense	(46		)	(41		)	(5		)	(84		)	(74		)	(10		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(5		)	(6		)	1			(11		)	(12		)	1
Adjusted EBITDA related to unconsolidated affiliates	18			15			3			34			30			4
Segment Adjusted EBITDA	$	148		$	149		$	(1	)	$	317		$	328		$	(11	)

Volumes. For the three and six months ended June 30, 2017 compared to the same periods last year, transported volumes increased primarily due to higher demand for exports to Mexico, along with the acquisition of an intrastate pipeline in northern Louisiana. These increases were partially offset by lower production volumes in the Barnett Shale region.

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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,
	2017		2016		Change			2017		2016		Change
Transportation fees	$	105	$	125	$	(20	)	$	229	$	259	$	(30	)
Natural gas sales and other	65		32		33			98		55		43
Retained fuel revenues	17		10		7			34		20		14
Storage margin, including fees	15		21		(6		)	23		19		4
Total segment margin	$	202	$	188	$	14		$	384	$	353	$	31

Segment Adjusted EBITDA. For the three and six months ended June 30, 2017 compared to the same periods last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:


•	decreases in transportation fees of $20 million and $30 million, respectively, due to renegotiated contracts resulting in lower billed volumes. For the six months ended June 30, 2017, the decrease in transportation fees is also partially offset by an increase of $6 million due to fees from renegotiated and newly initiated fixed fee contracts primarily on our Houston Pipeline system;


•	decreases of $13 million and $21 million, respectively, in storage margin (excluding net changes in unrealized gains of $7 million and $25 million, respectively, related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below; and


•	increases of $5 million and $10 million, respectively, in operating expenses primarily due to higher maintenance and project related expenses of $6 million and $7 million, respectively, as well as higher compression fuel expense of $2 million and $6 million, respectively, partially offset by fewer allocated expenses and lower capitalized overhead; partially offset by


•	increases of $29 million and $36 million, respectively, in natural gas sales and other (excluding changes in unrealized gains of $4 million and $7 million, respectively) primarily from higher realized gains from pipeline optimization activity due to more favorable market conditions;


•	increases of $4 million and $9 million, respectively, in retained fuel sales (excluding changes in unrealized gains of $3 million and $5 million, respectively) primarily due to higher market prices. The average spot price at the Houston Ship Channel location increased 53% for each of the three and six months ended June 30, 2017 compared to the same periods last year; and


•	increases of $3 million and $4 million, respectively, in Adjusted EBITDA related to unconsolidated affiliates due to the Trans-Pecos and Comanche Trail pipelines that were placed in service in 2017.

Storage margin was comprised of the following:



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
Withdrawals from storage natural gas inventory (MMBtu)	—			662,500			(662,500		)	23,092,500			21,657,500			1,435,000
Realized margin on natural gas inventory transactions	$	(5	)	$	8		$	(13	)	$	14		$	36		$	(22	)
Fair value inventory adjustments	(1		)	39			(40		)	(37		)	56			(93		)
Unrealized gains (losses) on derivatives	14			(33		)	47			32			(86		)	118
Margin recognized on natural gas inventory, including related derivatives	8			14			(6		)	9			6			3
Revenues from fee-based storage	7			7			—			14			13			1
Total storage margin	$	15		$	21		$	(6	)	$	23		$	19		$	4

The changes in storage margin were due primarily to the movement in market price of the physical storage gas and the financial derivatives used to hedge that gas.

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Interstate Transportation and Storage



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
Natural gas transported (MMBtu/d)	5,299,099			5,363,658			(64,559		)	5,476,343			5,599,352			(123,009		)
Natural gas sold (MMBtu/d)	17,035			21,539			(4,504		)	16,970			19,358			(2,388		)
Revenues	$	207		$	234		$	(27	)	$	442		$	493		$	(51	)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(67		)	(75		)	8			(141		)	(147		)	6
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(7		)	(11		)	4			(19		)	(23		)	4
Adjusted EBITDA related to unconsolidated affiliates	128			128			—			243			245			(2		)
Other	1			2			(1		)	2			2			—
Segment Adjusted EBITDA	$	262		$	278		$	(16	)	$	527		$	570		$	(43	)

Volumes. For the three months ended June 30, 2017 compared to the same period last year, transported volumes decreased primarily due to producer maintenance and production declines related to the Sea Robin pipeline. For the six months ended June 30, 2017 compared to the same period last year, the decrease in transported volumes was partially due to mild weather, the impact of which was approximately 75,000 MMBtu/d, as well as the impact of producer maintenance and production declines related to the Sea Robin pipeline during the second quarter of 2017.

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

•

a decrease in revenues of $21 million on the Panhandle, Trunkline and Transwestern pipelines, including a $14 million decrease in reservation revenues and a decrease of $7 million in gas parking service related revenues on the Panhandle and Trunkline pipelines, primarily due to lack of customer demand driven by weak spreads and mild weather. In addition, revenues decreased by $3 million on the Tiger pipeline due to contract restructuring and $2 million on the Sea Robin pipeline due to producer maintenance and production declines; partially offset by


•	a decrease in operating expenses of $8 million primarily due to lower allocated costs and system gas activity; and


•	a decrease in selling, general and administrative expenses of $4 million due to refunds associated with legal fees, insurance premiums and franchise taxes.

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

•

a decrease in revenues of $31 million on the Panhandle, Trunkline and Transwestern pipelines, including a $24 million decrease in reservation revenues and a decrease of $8 million in gas parking service related revenues on the Panhandle and Trunkline pipelines, primarily due to lack of customer demand driven by weak spreads and mild weather. In addition, revenues decreased by $14 million on the Tiger pipeline due to contract restructuring and $3 million on the Sea Robin pipeline due to producer maintenance and production declines; offset by


•	a decrease in operating expenses of $6 million primarily due to lower allocated costs; and


•	a decrease in selling, general and administrative expenses of $4 million due to refunds associated with legal fees, insurance premiums and franchise taxes.

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Midstream



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
Gathered volumes (MMBtu/d)	10,961,338			10,037,648			923,690			10,598,631			9,944,376			654,255
NGLs produced (Bbls/d)	473,699			468,732			4,967			438,498			449,853			(11,355		)
Equity NGLs (Bbls/d)	28,083			31,638			(3,555		)	26,809			30,585			(3,776		)
Revenues	$	1,615		$	1,330		$	285		$	3,252		$	2,422		$	830
Cost of products sold	1,044			870			174			2,168			1,548			620
Segment margin	571			460			111			1,084			874			210
Unrealized gains on commodity risk management activities	(3		)	—			(3		)	(19		)	—			(19		)
Operating expenses, excluding non-cash compensation expense	(152		)	(155		)	3			(313		)	(300		)	(13		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(11		)	(13		)	2			(34		)	(25		)	(9		)
Adjusted EBITDA related to unconsolidated affiliates	7			6			1			14			12			2
Segment Adjusted EBITDA	$	412		$	298		$	114		$	732		$	561		$	171

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

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017		2016		Change		2017		2016		Change
Gathering and processing fee-based revenues	$	442	$	398	$	44	$	846	$	780	$	66
Non fee-based contracts and processing	129		62		67		238		94		144
Total segment margin	$	571	$	460	$	111	$	1,084	$	874	$	210

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


•	an increase of $45 million in non-fee based margin due to higher realized crude, NGL and natural gas prices;


•	an increase of $1 million (excluding unrealized gains of $3 million) in non-fee based margin due to higher benefit from settled derivatives used to hedge commodity margins;


•	an increase of $18 million in non-fee based margin due to volume increases in the Permian, partially offset by declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions;


•	an increase of $20 million in fee-based revenue due to minimum volume commitments in the South Texas region, as well as volume increases in the Permian and Northeast regions. These increases were partially offset by declines in South Texas, North Texas and the Mid-Continent/Panhandle regions; and


•	an increase of $24 million in fee-based revenue due to recent acquisitions, including PennTex; partially offset by


•	a decrease of $3 million in operating expenses primarily due to lower outside service costs and capitalized overhead; and


•	a decrease in general and administrative expenses due to a favorable impact of $11 million from the adjustment of certain reserves that were recorded in connection with contingent matters, partially offset by an increase of $2 million in shared

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services allocation, a $1 million increase in insurance allocation, and a $3 million increase due to additional costs from the PennTex acquisition.

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


•	an increase of $93 million in non-fee based margin due to higher realized crude, NGL and natural gas prices;


•	an increase of $36 million in non-fee based margin due to volume increases in the Permian partially offset by declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions;


•	an increase of $24 million in fee-based revenue due to minimum volume commitments in the South Texas region, as well as volume increases in the Permian and Northeast regions. These increases were offset by declines in South Texas, North Texas and the Mid-Continent/Panhandle regions; and


•	an increase of $42 million in fee-based revenue due to recent acquisitions, including PennTex; partially offset by


•	a decrease of $4 million (excluding unrealized gains of $19 million) in non-fee based margin due to lower benefit from settled derivatives used to hedge commodity margins;


•	an increase of $13 million in operating expenses primarily due to recent acquisitions, including PennTex; and

•

an increase of $9 million in general and administrative expenses primarily due to a decrease of $4 million in capitalized overhead, a $5 million increase in shared services allocation, a $3 million increase in insurance allocation, and $5 million additional costs from the PennTex acquisition, partially offset by a favorable impact of $11 million from the adjustment of certain reserves that had previously been recorded in connection with contingent matters.

NGL and Refined Products Transportation and Services



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
NGL transportation volumes (MBbls/d)	835			741			94			823			729			94
Refined products transportation volumes (MBbls/d)	643			556			87			633			553			80
NGL and refined products terminal volumes (MBbls/d)	791			773			18			799			762			37
NGL fractionation volumes (MBbls/d)	431			345			86			430			356			74
Revenues	$	1,768		$	1,487		$	281		$	4,045		$	2,820		$	1,225
Cost of products sold	1,245			1,039			206			2,965			1,941			1,024
Segment margin	523			448			75			1,080			879			201
Unrealized (gains) losses on commodity risk management activities	(4		)	10			(14		)	(54		)	32			(86		)
Operating expenses, excluding non-cash compensation expense	(129		)	(107		)	(22		)	(258		)	(216		)	(42		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(17		)	(15		)	(2		)	(36		)	(29		)	(7		)
Adjusted EBITDA related to unconsolidated affiliates	18			16			2			35			32			3
Inventory valuation adjustments	—			(11		)	11			5			(9		)	14
Other	—			—			—			1			—			1
Segment Adjusted EBITDA	$	391		$	341		$	50		$	773		$	689		$	84

Volumes. For the three and six months ended June 30, 2017 compared to the same periods last year, NGL transportation volumes increased in the major producing regions, including the Permian, Louisiana and the Eagle Ford, but declined slightly in North Texas.

Refined products transportation volumes increased for the three and six months ended June 30, 2017 due to increased throughput from certain Midwest and Northeast refineries.

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Average daily fractionated volumes increased for the three and six months ended June 30, 2017 increased 25% and 21%, respectively, compared to the same periods last year primarily due to the commissioning of our fourth fractionator at Mont Belvieu, Texas, in October 2016 which has a capacity of 120,000 Bbls/d, as well as increased producer volumes as mentioned above.

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,
	2017		2016		Change		2017		2016		Change
Fractionators and Refinery services margin	$	114	$	93	$	21	$	235	$	193	$	42
Transportation margin	241		207		34		474		403		71
Storage margin	53		49		4		110		98		12
Terminal Services margin	81		79		2		168		156		12
Marketing margin	34		20		14		93		29		64
Total segment margin	$	523	$	448	$	75	$	1,080	$	879	$	201

Segment Adjusted EBITDA. For the three and six months ended June 30, 2017 compared to the same periods last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impact of the following:


•	increases in storage margin of $4 million and $12 million, respectively, primarily due to increased volumes from our Mont Belvieu fractionators;


•	increases in transportation margin of $34 million and $71 million, respectively, primarily due to higher volumes on our Texas NGL pipelines and the ramp-up of volumes on our Mariner East system;


•	increases in fractionation and refinery services margin of $23 million and $40 million, respectively, (excluding changes in unrealized losses of $2 million and changes in unrealized gains of $2 million, respectively) primarily due to higher NGL volumes from most major producing regions, as noted above; and


•	increases in terminal services margin of $2 million and $12 million, respectively, due to higher terminal volumes from the Mariner NGL projects; offset by


•	an increase of $8 million and a decrease of $5 million, respectively, in marketing margin (excluding changes in unrealized gains of $16 million and $84 million, respectively) primarily due to the timing of the recognition of margin from optimization activities;

•

increases of $22 million and $42 million, respectively, in operating expenses primarily due to increased utilities costs associated with our fourth fractionator at Mont Belvieu and the Mariner project ramp-up at the Marcus Hook Industrial Complex of $3 million and $13 million, respectively, higher ad valorem tax expenses of $6 million and $13 million, respectively, primarily from our Lone Star Express pipeline beginning service in 2016, and higher employee expenses associated with assets placed in service of $10 million and $11 million, respectively, project related service expenses of $2 million and $7 million, respectively; and


•	increases of $2 million and $7 million, respectively, in selling, general and administrative expenses for the three and six months ended June 30, 2017 due to higher allocations and lower capitalized overhead resulting from reduced capital spending.

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Crude Oil Transportation and Services



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
Crude Transportation Volumes (MBbls/d)	3,484			2,639			845			3,275			2,553			722
Crude Terminals Volumes (MBbls/d)	1,921			1,497			424			1,919			1,507			412
Revenues	$	2,586		$	1,989		$	597		$	5,275		$	3,454		$	1,821
Cost of products sold	2,217			1,670			547			4,661			2,868			1,793
Segment margin	369			319			50			614			586			28
Unrealized gains on commodity risk management activities	(2		)	—			(2		)	(2		)	—			(2		)
Operating expenses, excluding non-cash compensation expense	(116		)	(63		)	(53		)	(186		)	(114		)	(72		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(32		)	(14		)	(18		)	(49		)	(28		)	(21		)
Inventory valuation adjustments	58			(121		)	179			51			(97		)	148
Adjusted EBITDA related to unconsolidated affiliates	2			3			(1		)	6			5			1
Segment Adjusted EBITDA	$	279		$	124		$	155		$	434		$	352		$	82

Segment Adjusted EBITDA. For the three months ended June 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the following:


•	an increase of $66 million due to the impact of LIFO accounting; and

•

an increase of $129 million due to improved results from our crude oil pipelines, joint ventures and terminal activities, which was primarily attributed to expansion projects and the acquisition of Vitol Inc.’s crude oil assets in the fourth quarter of 2016, resulting in an increase of $109 million, as well as increased volumes and lower operating expenses from our existing crude pipeline and terminal assets resulting in an increase of $20 million; partially offset by


•	a decrease of $21 million due to lower results from our crude oil acquisition and marketing activities; and


•	an increase of $18 million in selling, general and administrative expenses driven largely by merger-related expenses and legal and environmental reserves.

Segment Adjusted EBITDA. For the six months ended June 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the following:

•

an increase of $197 million due to improved results from our crude oil pipelines, joint ventures, and terminal activities, which was primarily attributed to expansion projects and the acquisition of Vitol Inc.’s crude oil assets in the fourth quarter of 2016, resulting in an increase of $159 million, as well as increased volumes and lower operating expenses from our existing crude pipeline and terminal assets resulting in an increase of $38 million; partially offset by


•	a decrease of $46 million due to the impact of LIFO accounting. This unfavorable LIFO impact is expected to be reversed in future periods as commodity prices fall or the inventory positions are liquidated;


•	a decrease of $45 million due to lower results from our crude oil acquisition and marketing activities; and


•	an increase of $21 million in selling, general and administrative expenses driven largely by merger-related expenses and legal and environmental reserves.

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All Other



	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Change			2017			2016			Change
Revenues	$	870		$	711		$	159		$	1,640		$	1,565		$	75
Cost of products sold	794			625			169			1,462			1,386			76
Segment margin	76			86			(10		)	178			179			(1		)
Unrealized (gains) losses on commodity risk management activities	(4		)	15			(19		)	(17		)	18			(35		)
Operating expenses, excluding non-cash compensation expense	(34		)	(16		)	(18		)	(55		)	(37		)	(18		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(29		)	(19		)	(10		)	(50		)	(46		)	(4		)
Adjusted EBITDA related to unconsolidated affiliates	76			85			(9		)	156			146			10
Other	21			24			(3		)	26			48			(22		)
Eliminations	1			5			(4		)	(8		)	(26		)	18
Segment Adjusted EBITDA	$	107		$	180		$	(73	)	$	230		$	282		$	(52	)

Amounts reflected in our all other segment primarily include:


•	our equity method investment in limited partnership units of Sunoco LP consisting of 43.5 million units, representing 43.7% of Sunoco LP’s total outstanding common units;


•	our natural gas marketing and compression operations;


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


•	our investment in Coal Handling, an entity that owns and operates end-user coal handling facilities.

For the three and six months ended June 30, 2017 compared to the same periods last year, Segment Adjusted EBITDA related to our all other segment decreased due to the following:


•	higher operating expenses of $18 million due to an increase in revenue-generating horsepower in our compression business;


•	higher selling, general and administrative expenses of $10 million and $4 million, respectively, primarily from higher transaction-related expenses;


•	decreases of $27 million and $5 million, respectively, in Adjusted EBITDA related to our investment in PES; and


•	decreases of $19 million and $38 million, respectively, related to the termination of management fees paid by ETE that ended in 2016; partially offset by


•	a one-time fee of $15 million received from a joint venture affiliate in the three months ended June 30, 2017.

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.

For the year ending December 31, 2017, we expect to spend approximately $3.9 billion on capital expenditure funding, net of $1.0 billion financed at the asset level and net an approximately $1.4 billion reduction related to the sale of a portion of our interest in the Rover pipeline project.

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

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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 changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash unit-based compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, 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, 2017 compared to six months ended June 30, 2016. Cash provided by operating activities during 2017 was $1.65 billion compared to $1.43 billion for 2016 and net income was $656 million and $848 million for 2017 and 2016, respectively. The difference between net income and cash provided by operating activities for the six months ended June 30, 2017 primarily consisted of net changes in operating assets and liabilities of $410 million and non-cash items totaling $1.22 billion.

The non-cash activity in 2017 and 2016 consisted primarily of depreciation, depletion and amortization of $1.12 billion and $966 million, respectively, non-cash compensation expense of $38 million and $38 million, respectively, and equity in earnings of unconsolidated affiliates of $12 million and $195 million, respectively. Non-cash activity in 2017 also included deferred income taxes of $121 million and inventory valuation adjustments of $56 million.

Cash paid for interest, net of interest capitalized, was $691 million and $669 million for the six months ended June 30, 2017 and 2016, respectively.

Capitalized interest was $105 million and $111 million for the six months ended June 30, 2017 and 2016, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in 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, 2017 compared to six months ended June 30, 2016. Cash used in investing activities during 2017 was $1.49 billion compared to $1.23 billion for 2016. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2017 were $2.83 billion compared to $3.45 billion for 2016. Additional detail related to our capital expenditures is provided in the table below. 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. During 2016, we received $2.20 billion in cash related to the contribution of our Sunoco, Inc. retail business to Sunoco LP.

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



	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Intrastate transportation and storage	$	23	$	13	$	36
Interstate transportation and storage	979		27		1,006
Midstream	560		45		605
NGL and refined products transportation and services	1,096		33		1,129
Crude oil transportation and services	231		21		252
All other (including eliminations)	70		28		98
Total capital expenditures	$	2,959	$	167	$	3,126

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.

Six months ended June 30, 2017 compared to six months ended June 30, 2016. Cash used in financing activities during 2017 was $252 million compared to $342 million for 2016. In 2017 and 2016, we received net proceeds from Common Unit offerings of $990 million and $408 million, respectively. In 2016, our subsidiaries received $667 million in net proceeds from the issuance of common units. During 2017, we had a net increase in our debt level of $258 million compared to a net increase of $444 million for 2016. We have paid distributions of $1.70 billion to our partners in 2017 compared to $1.81 billion in 2016. We have also paid distributions of $186 million to noncontrolling interests in 2017 compared to $209 million in 2016. In addition, we have received capital contributions of $456 million in cash from noncontrolling interests in 2017 compared to $161 million in 2016. During 2017, we repurchased our outstanding Preferred Units for cash of $53 million and incurred debt issuance costs of $20 million.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	June 30, 2017			December 31, 2016
ETP Senior Notes	$	20,540		$	19,440
Transwestern Senior Notes	575			657
Panhandle Senior Notes	1,085			1,085
Sunoco, Inc. Senior Notes	65			465
Sunoco Logistics Senior Notes	5,350			5,350
Credit facilities and commercial paper:
ETLP $3.75 billion Revolving Credit Facility due November 2019⁽¹⁾	1,542			2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020⁽²⁾	1,673			1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017⁽³⁾	—			630
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			1,100
PennTex $275 million Revolving Credit Facility due December 2019	148			168
Other long-term debt	5			30
Unamortized premiums, net of discounts and fair value adjustments	94			116
Deferred debt issuance costs	(183		)	(180		)
Total debt	33,394			32,930
Less: current maturities of long-term debt	1,365			1,189
Long-term debt, less current maturities	$	32,029		$	31,741


⁽¹⁾	Includes $1.54 billion and $777 million of commercial paper outstanding at June 30, 2017 and December 31, 2016, respectively.

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⁽²⁾	Includes $241 million and $50 million of commercial paper outstanding at June 30, 2017 and December 31, 2016, respectively.


⁽³⁾	Sunoco Logistics’ $1.00 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics had the ability and intent to refinance such borrowings on a long-term basis. This 364-Day Credit Facility was terminated and repaid in May 2017.

Credit Facilities and Commercial Paper

ETLP Credit Facility

Sunoco Logistics Credit Facilities

Bakken Credit Facility

PennTex Revolving Credit Facility

Covenants Related to Our Credit Agreements

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

CASH DISTRIBUTIONS

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The following table shows the target distribution levels and distribution “splits” between the general partner and the holders of the Partnership’s common units:



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

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

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

Following are distributions declared and/or paid by the Partnership subsequent to the Sunoco Logistics Merger:



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

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,
	2017			2016
	ETP			Energy Transfer Partners, L.P.			Sunoco Logistics
Limited Partners:
Common Units held by public	$	1,156		$	1,053		$	223
Common Units held by ETP	—			—			66
Common Units held by ETE	30			5			—
Class H Units held by ETE	—			171			—
General Partner interest	8			16			7
Incentive distributions held by ETE	773			666			183
IDR relinquishments	(319		)	(144		)	—
Total distributions declared to partners	$	1,648		$	1,767		$	479

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The Partnership’s critical accounting policies have not changed subsequent to those reported in Exhibit 99.3 to its Form 8-K filed on May 8, 2017. The following information is provided to supplement the Form 8-K disclosures specifically related to impairment of long-lived assets and goodwill.

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

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

The Partnership determined the fair value of its reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

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

The goodwill impairments recorded by the Partnership during the years ended December 31, 2016 and 2015 represented all of the goodwill within the respective reporting units.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in Exhibit 99.3 to the Partnership’s Current Report on Form 8-K filed with the SEC on May 8, 2017, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed for the year ended December 31, 2016. Since December 31, 2016, there have been no material changes to our primary market risk exposures or how those exposures are managed.

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Commodity Price Risk

The table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power, and barrels for natural gas liquids, crude and refined products. Dollar amounts are presented in millions.



	June 30, 2017							December 31, 2016
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	465,000		$	—		$	—	(682,500	)	$	—		$	—
Basis Swaps IFERC/NYMEX⁽¹⁾	33,112,500		3			1		2,242,500		(1		)	—
Options – Puts	11,500,000		—			—		—		—			—
Power (Megawatt):
Forwards	497,530		1			1		391,880		(1		)	1
Futures	(212,880	)	—			—		109,564		—			—
Options – Puts	(364,000	)	—			2		(50,400	)	—			—
Options – Calls	607,200		—			1		186,400		1			—
Crude (Bbls) – Futures	(1,569,000	)	4			7		(617,000	)	(4		)	6
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,630,000	)	(2		)	2		10,750,000		2			—
Swing Swaps IFERC	39,900,000		1			1		(5,662,500	)	(1		)	1
Fixed Swaps/Futures	(39,250,000	)	6			5		(52,652,500	)	(27		)	19
Forward Physical Contracts	(9,302,540	)	3			4		(22,492,489	)	1			8
Natural Gas Liquid (Bbls) – Forwards/Swaps	(4,501,400	)	7			22		(5,786,627	)	(40		)	35
Refined Products (Bbls) – Futures	(803,000	)	(3		)	6		(2,240,000	)	(16		)	17
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(32,440,000	)	(1		)	—		(36,370,000	)	2			1
Fixed Swaps/Futures	(32,440,000	)	7			10		(36,370,000	)	(26		)	14


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

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

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Interest Rate Risk

As of June 30, 2017, we had $2.69 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $27 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

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



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	June 30, 2017		December 31, 2016
July 2017⁽²⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% 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 $235 million as of June 30, 2017. 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 $23 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, 2017 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

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

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

There have been no other changes in our internal controls over financial reporting (as defined in Rule 13(a)–15(f) or Rule 15d–15(f) of the Exchange Act) during the three months ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Exhibit 99.3 to our Current Report on Form 8-K filed with the SEC on May 8, 2017 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, 2017.

The EPA has brought a federal court action against SPLP and Mid-Valley for violations of the Clean Water Act (“CWA”). The United States’ complaint alleges that SPLP and Mid-Valley violated Sections 311(b)(7)(A) and 301(a) of the CWA when, during three separate releases, pipelines operated by SPLP and owned by SPLP or Mid-Valley Pipeline Company discharged oil. See 33 U.S.C. §§ 1311(a) and 1321(b)(7)(A). In particular, the three releases at issue occurred (1) on February 23, 2013, in Tyler County, Texas, when a reported 550 barrels of oil were discharged; (2) on October 13, 2014, in Caddo Parish, Louisiana, when a reported 4,509 barrels of oil were discharged; and (3) on January 20, 2015, in Grant County, Oklahoma, when a reported 40 barrels of oil were discharged. Potential fines from the DOJ are $7 million and from the State of Louisiana are approximately $1 million. The Partnership is currently in discussions to resolve these matters.

Mont Belvieu received a Notice of Enforcement (“NOE”) with an Agreed Order from the Texas Commission on Environmental Quality and has a pending settlement for $1 million. The NOE was for the two violations.

Energy Transfer Company Field Services, LLC received a settlement offer from the New Mexico Environmental Department (“NMED”) on July 20, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. The alleged violation occurred during the period of September 1, 2016 through December 31, 2016. The NMED is offering to settle the violations with a civil penalty of $1 million.

Energy Transfer Company Field Services, LLC received a settlement offer from the NMED on May 25, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. The alleged violation occurred during the period of March 24, 2014 through September 30, 2014. The NMED is offering to settle the violations with a civil penalty of $0.4 million.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in our Annual Report on Form 10-K for our previous fiscal year ended December 31, 2016 and in Exhibit 99.3 to our Current Report on Form 8-K filed with the SEC on May 8, 2017.

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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
3.1		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1 Registration Statement, File No. 333-71968, filed October 22, 2001).
3.2		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed September 1, 2015).
3.3		Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of April 28, 2017 (incorporated by reference to Exhibit 3.3 of Form 8-K, File No. 1-31219, filed April 28, 2017).
3.4		Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated April 28, 2017 (incorporated by reference to Exhibit 3.4 of Form 8-K, File No. 1-31219, filed April 28, 2017).
10.1		Michael J. Hennigan Separation Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed May 31, 2017).
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.
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.

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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, 2017	By:	/s/ A. Troy Sturrock
			A. Troy Sturrock
			Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)

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