10-Q

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

or

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

Commission file number 1-11727

ENERGY TRANSFER, LP

(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.

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes¨Noý

Energy Transfer, LP meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

FORM 10-Q

ENERGY TRANSFER, LP 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	31
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
ITEM 4. CONTROLS AND PROCEDURES	35
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	36
ITEM 1A. RISK FACTORS	36
ITEM 6. EXHIBITS	37
SIGNATURE	38

i

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer, LP (the “Partnership” or “ETLP”) 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.

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	The Partnership’s $3.75 billion revolving credit facility
ETP	Energy Transfer Partners, L.P. subsequent to the close of the merger of Sunoco Logistics Partners L.P. and Energy Transfer Partners, L.P.

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ETP GP	Energy Transfer Partners GP, L.P., the general partner of ETP
ETP Holdco	ETP Holdco Corporation
ETP LLC	Energy Transfer Partners, L.L.C., the general partner of ETP GP
Exchange Act	Securities Exchange Act of 1934
FEP	Fayetteville Express Pipeline LLC
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company, LLC
GAAP	accounting principles generally accepted in the United States of America
HPC	RIGS Haynesville Partnership Co. 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
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.

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	June 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	209		$	360
Accounts receivable, net	1,203			3,002
Accounts receivable from related companies	1,116			209
Inventories	653			1,712
Income taxes receivable	148			128
Derivative assets	5			20
Other current assets	142			298
Total current assets	3,476			5,729
Property, plant and equipment	47,256			58,220
Accumulated depreciation and depletion	(6,809		)	(7,303		)
	40,447			50,917
Advances to and investments in unconsolidated affiliates	11,585			4,280
Other non-current assets, net	628			672
Intangible assets, net	3,962			4,696
Goodwill	2,294			3,897
Total assets	$	62,392		$	70,191

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

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ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	June 30, 2017		December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	956	$	2,900
Accounts payable to related companies	229		43
Derivative liabilities	2		166
Accrued and other current liabilities	2,111		1,905
Current maturities of long-term debt	1,365		1,189
Total current liabilities	4,663		6,203
Long-term debt, less current maturities	24,968		31,741
Long-term notes payable – related company	—		250
Non-current derivative liabilities	201		76
Deferred income taxes	4,243		4,394
Other non-current liabilities	934		952
Commitments and contingencies
Preferred Units	—		33
Redeemable noncontrolling interests	—		15
Equity:
Partner’s capital	24,429		18,634
Accumulated other comprehensive income	7		8
Total partner’s capital	24,436		18,642
Noncontrolling interest	2,947		7,885
Total equity	27,383		26,527
Total liabilities and equity	$	62,392	$	70,191

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

2

ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)

(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	1,478			1,150			3,025			2,090
Crude sales	724			1,713			3,071			2,923
Gathering, transportation and other fees	982			1,045			2,006			2,005
Refined product sales	155			234			626			479
Other	377			452			871			740
Total revenues	4,738			5,289			11,633			9,770
COSTS AND EXPENSES:
Cost of products sold	3,130			3,630			8,322			6,598
Operating expenses	373			374			752			722
Depreciation, depletion and amortization	473			496			1,033			966
Selling, general and administrative	86			74			196			155
Total costs and expenses	4,062			4,574			10,303			8,441
OPERATING INCOME	676			715			1,330			1,329
OTHER INCOME (EXPENSE):
Interest expense, net	(320		)	(317		)	(659		)	(636		)
Equity in earnings of unconsolidated affiliates	23			119			96			195
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Other, net	67			27			93			44
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	421			463			840			781
Income tax expense (benefit)	71			(9		)	126			(67		)
NET INCOME	350			472			714			848
Less: Net income attributable to noncontrolling interest	89			102			129			167
NET INCOME ATTRIBUTABLE TO PARTNERS	$	261		$	370		$	585		$	681

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

3

ENERGY TRANSFER, LP 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	$	350		$	472		$	714		$	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	349			476			713			838
Less: Comprehensive income attributable to noncontrolling interest	89			102			129			167
Comprehensive income attributable to partners	$	260		$	374		$	584		$	671

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

4

ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2017

(Dollars in millions)

(unaudited)

	Partner’s Capital			Accumulated Other Comprehensive Income			Noncontrolling Interest			Total
Balance, December 31, 2016	$	18,634		$	8		$	7,885		$	26,527
Distributions to partners	(889		)	—			—			(889		)
Distributions to noncontrolling interest	—			—			(167		)	(167		)
Units issued for cash	885			—			—			885
Capital contributions from noncontrolling interest	—			—			1,432			1,432
PennTex unit acquisition	(49		)	—			(231		)	(280		)
Sunoco Logistics Merger	4,033			—			(6,802		)	(2,769		)
Sale of Bakken Pipeline interest	1,260			—			740			2,000
Other comprehensive income, net of tax	—			(1		)	—			(1		)
Other, net	(30		)	—			(39		)	(69		)
Net income	585			—			129			714
Balance, June 30, 2017	$	24,429		$	7		$	2,947		$	27,383

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

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ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Six Months Ended June 30,
	2017			2016
OPERATING ACTIVITIES
Net income	$	714		$	848
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,033			966
Deferred income taxes	122			(79		)
Amortization included in interest expense	(1		)	(12		)
Inventory valuation adjustments	2			(106		)
Unit-based compensation expense	37			38
Distributions on unvested awards	(15		)	(13		)
Equity in earnings of unconsolidated affiliates	(96		)	(195		)
Distributions from unconsolidated affiliates	353			199
Other non-cash	(135		)	(124		)
Net change in operating assets and liabilities, net of effects of acquisition	(942		)	(96		)
Net cash provided by operating activities	1,072			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	(251		)	—
Deconsolidation of Sunoco Logistics	(75		)	—
Capital expenditures, excluding allowance for equity funds used during construction	(2,844		)	(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	95			56
Proceeds from the sale of assets	23			7
Change in restricted cash	—			(2		)
Other	(2		)	(1		)
Net cash used in investing activities	(1,549		)	(1,225		)
FINANCING ACTIVITIES
Proceeds from borrowings	11,330			7,811
Repayments of long-term debt	(10,953		)	(7,514		)
Cash (paid) received from affiliate notes	(255		)	147
Units issued for cash	885			408
Subsidiary units issued for cash	—			667
Capital contributions from noncontrolling interest	444			161
Distributions to partners	(889		)	(1,813		)
Distributions to noncontrolling interest	(167		)	(209		)
Redemption of Series A Preferred Units	(53		)	—
Debt issuance costs	(20		)	—
Other	4			—
Net cash provided by (used in) financing activities	326			(342		)
Decrease in cash and cash equivalents	(151		)	(141		)
Cash and cash equivalents, beginning of period	360			527
Cash and cash equivalents, end of period	$	209		$	386

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

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ENERGY TRANSFER, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts are in millions)

(unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. Energy Transfer, LP and its subsidiaries are collectively referred to herein as the “Partnership,” “we,” “us,” “our” or “ETLP.”

In April 2017, Energy Transfer Partners, L.P. merged with a subsidiary of Sunoco Logistics Partners L.P. (the “Sunoco Logistics Merger”), at which time it 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.” Following the completion of the Sunoco Logistics Merger, ETLP has no remaining publicly traded units outstanding. Additionally, subsequent to the Sunoco Logistics Merger, ETLP deconsolidated Sunoco Logistics 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 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.

• 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 a50%interest in FEP, which owns100%of the Fayetteville Express interstate natural gas pipeline.

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

• CrossCountry, which indirectly owns a50%interest in Citrus, which owns100%of the FGT interstate natural gas pipeline.

• ETC MEP, which directly owns a50%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.

Our financial statements reflect the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

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•midstream;

•liquids transportation and services;

•investment in ETP; and

•all other.

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in Energy Transfer Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2016. 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 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, Revenuefrom 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

8

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, 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. CASH AND CASH EQUIVALENTS

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

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

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

	Six Months Ended June 30,
	2017			2016
Accounts receivable	$	136		$	(471	)
Accounts receivable from related companies	(888		)	(129		)
Inventories	132			(157		)
Other current assets	86			(53		)
Other non-current assets, net	(147		)	8
Accounts payable	(49		)	509
Accounts payable to related companies	187			21
Accrued and other current liabilities	(408		)	(22		)
Other non-current liabilities	40			20
Derivative assets and liabilities, net	(31		)	178
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(942	)	$	(96	)

Non-cash investing and financing activities are as follows:

	Six Months Ended June 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,230	$	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	$	—

3. INVENTORIES

Inventories consisted of the following:

	June 30, 2017		December 31, 2016
Natural gas and NGLs	$	449	$	699
Crude oil	—		683
Refined products	—		113
Spare parts and other	204		217
Total inventories	$	653	$	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.

4. ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Upon the completion of the Sunoco Logistics Merger, the Partnership deconsolidated ETP (formerly Sunoco Logistics). The Partnership holds an equity method investment in ETP due to its ownership of ETP Class E, Class G and Class K units.

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The Partnership previously had outstanding 8.9 million Class E Units, 90.7 million Class G Units and 101.5 million Class K Units, all of which were held by wholly-owned subsidiaries of the Partnership and were therefore eliminated in the Partnership’s consolidated financial statements. In connection with the Sunoco Logistics Merger, all of the Partnership’s outstanding Class E, Class G and Class K units were cancelled and converted into an equal number of newly created Class E, Class G and Class K units representing limited partner interests in ETP, with the same rights, preferences, privileges, duties and obligations as such classes had immediately prior to the Sunoco Logistics Merger, as described below. Consequently, the ETP Class E, Class G and Class K units are reflected as an equity method investment in ETP by the Partnership subsequent to the Sunoco Logistics Merger. The Partnership’s equity in earnings and cash distributions related to the Class E, Class G and Class K units is as follows: (i) the Class E Units are entitled to aggregate earnings allocation and cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, (ii) the Class G Units are entitled to earnings allocation equal to ETPs income or loss excluding any income or loss generated by ETP Holdco or its consolidated subsidiaries and aggregate cash distributions equal to 26% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year, and (iii) the Class K Units are entitled to aggregate earnings allocation and cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. The investment in ETP has been recorded in the Partnership’s balance sheet at the historical carrying value as of the date of the Sunoco Logistics Merger.

The following table presents aggregated selected income statement data for ETP and Citrus (on a 100% basis for all periods presented):

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
ETP
Revenue	$	6,576	$	5,289	$	13,471	$	9,770
Operating income	732		715		1,386		1,329
Net income	292		472		656		848
Citrus
Revenue	$	219	$	214	$	409	$	405
Operating income	135		132		240		241
Net income	59		56		101		98

The Partnership has other equity method investments which were not, individually or in the aggregate, significant to our consolidated financial statements.

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 $27.55 billion and $26.37 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 endedJune 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	74			74			—
Crude – Futures	9			9			—
Total commodity derivatives	151			132			19
Total assets	$	151		$	132		$	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	(68		)	(68		)	—
Crude – Futures	(5		)	(5		)	—
Total commodity derivatives	(123		)	(108		)	(15		)
Total liabilities	$	(324	)	$	(108	)	$	(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. DEBT OBLIGATIONS

Credit Facilities and Commercial Paper

ETLP Credit Facility

The ETLP Credit Facility allows for borrowings of up to$3.75 billionand 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 billionETLP Credit Facility.As ofJune 30, 2017, the ETLP Credit Facility had$1.54 billionof outstanding borrowings, all of which was commercial paper.

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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 billioncredit facility provides substantially all of the remaining capital necessary to complete the projects. As ofJune 30, 2017, $2.50 billionwas outstanding under this credit facility.

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”). As of June 30, 2017, the PennTex Revolving Credit Facility had$148 millionof 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 ofJune 30, 2017.

7. PREFERRED UNITS

In January 2017, Energy Transfer Partners, L.P. repurchased all of its1.9 millionoutstanding Preferred Units for cash in the aggregate amount of$53 million.

8. EQUITY

In connection with the Sunoco Logistics 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.

Common Units

Upon the completion of the Sunoco Logistics Merger, the Partnership’s equity distribution program, distribution reinvestment program and equity incentive plans have been terminated.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETLP indirectly owns a60%membership interest and ETP indirectly owns a40%membership interest, sold a49%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 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”).The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETLP continues to consolidate Dakota Access and ETCO subsequent to this transaction.Upon closing, ETLP and ETP collectively own a38.25%interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”), and MarEn Bakken Company owns36.75%and Phillips 66 owns25.00%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$20.00per 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.

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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

9. INCOME TAXES

For the three and six months ended June 30, 2017, the Partnership’s income tax expenseincluded 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 millionduring 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.

10. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012,ETLP (formerly Energy Transfer Partners, L.P.)agreed to provide contingent residual support of$1.55 billionof 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 its7.00%senior notes. The remaining outstanding7.00%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 millionprincipal amount of6.375%senior notes due 2023 issued by Sunoco LP, (ii)$800 millionprincipal amount of6.25%senior notes due 2021 issued by Sunoco LP and (iii)$2.035 billionaggregate 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.

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.

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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through2034. 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	$	14	$	21	$	34	$	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 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

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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 ofJune 30, 2017, Sunoco, Inc. is a defendant insixcases, 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.Fourof 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 of9sites 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 of9New 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 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.

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

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

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 ofJune 30, 2017andDecember 31, 2016, accruals of approximately$71 millionand$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.

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$900,000in 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 at27sites 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.

Noamounts have been recorded in ourJune 30, 2017orDecember 31, 2016consolidated 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 millionfor the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 millionto 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 ofJune 30, 2017, Sunoco, Inc. had been named as a PRP at approximately49identified 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	$	30	$	26
Non-current	275		283
Total environmental liabilities	$	305	$	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 thethree months ended June 30,2017and2016, Sunoco, Inc. recorded$8 millionand$8 million, respectively, of expenditures related to environmental cleanup programs. During thesix months ended June 30,2017and2016, Sunoco, Inc. recorded$10 millionand$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$200,000to 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.

11. 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 liquids 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	(4,562,000	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	—		—	(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
		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	16		24		(13		)	(52		)
Interest rate derivatives	—		—		(201		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	143		362		(323		)	(662		)
Total derivatives	$	151	$	362	$	(324	)	$	(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)	16			24			(13		)	(52		)
Broker cleared derivative contracts	Other current assets	135			338			(110		)	(420		)
Total gross derivatives		151			362			(324		)	(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		$	30		$	20		$	(203	)	$	(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	8			(48		)	(2		)	(43		)
Interest rate derivatives	Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Embedded derivatives	Other, net	—			(4		)	1			(4		)
Total		$	(2	)	$	(140	)	$	5		$	(214	)

12. 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 inNote 8.

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	$	42	$	133	$	160	$	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
ETP	762		—
Sunoco LP	179		96
PES	1		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	59		65
Total accounts receivable from related companies:	$	1,116	$	209
Accounts payable to related companies:
ETP	$	47	$	—
Sunoco LP	177		20
FGT	—		1
Lake Charles LNG	2		3
Other	3		19
Total accounts payable to related companies:	$	229	$	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	)

13. REPORTABLE SEGMENTS

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;

•liquids transportation and services;

•investment in ETP; and

•all other.

As discussed in Note 1, Sunoco Logistics changed its name to ETP upon the completion of the Sunoco Logistics Merger. Accordingly, the reportable segment previously named “Investment in Sunoco Logistics” has been renamed “Investment in ETP.” For periods prior to the Sunoco Logistics Merger, this reportable segment reflects the consolidated results of Sunoco Logistics. For periods subsequent to the Sunoco Logistics Merger, this segment reflects the investments in ETP’s Class E, Class G and Class K units that continue to be held by the Partnership’s subsidiaries, which are accounted for under the equity method.

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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 ETLP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETLP 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 ofJune 30, 2017, the Partnership’s interest in Sunoco LP common units consisted of43.5 millionunits, representing43.7%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 liquids transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in ETP 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	640			690			1,205			1,217
Intersegment revenues	977			640			2,049			1,205
	1,617			1,330			3,254			2,422
Liquids transportation and services:
Revenues from external customers	1,391			1,099			2,899			1,928
Intersegment revenues	112			11			226			101
	1,503			1,110			3,125			2,029
Investment in ETP:
Revenues from external customers	991			2,250			4,176			3,979
Intersegment revenues	11			18			45			66
	1,002			2,268			4,221			4,045
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	(1,214		)	(905		)	(2,618		)	(1,883		)
Total revenues	$	4,738		$	5,289		$	11,633		$	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
Liquids transportation and services	319			220			578			447
Investment in ETP	252			245			530			594
All other	107			180			230			282
Total	1,500			1,370			2,914			2,782
Depreciation, depletion and amortization	(473		)	(496		)	(1,033		)	(966		)
Interest expense, net	(320		)	(317		)	(659		)	(636		)
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Non-cash unit-based compensation expense	(14		)	(19		)	(37		)	(38		)
Unrealized gains (losses) on commodity risk management activities	34			(18		)	98			(81		)
Inventory valuation adjustments	—			132			2			106
Adjusted EBITDA related to unconsolidated affiliates	(347		)	(252		)	(586		)	(471		)
Equity in earnings of unconsolidated affiliates	23			119			96			195
Other, net	43			25			65			41
Income before income tax expense (benefit)	$	421		$	463		$	840		$	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		18,011
Liquids transportation and services	12,651		11,296
Investment in ETP	7,462		18,819
All other	5,757		6,068
Total assets	$	62,392	$	70,191

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

AND RESULTS OF OPERATIONS

(Tabular dollar amounts 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; (ii) Energy Transfer Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 24, 2017; and (iii) our management’s discussion and analysis of financial condition and results of operations included in our 2016 Form 10-K. 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 the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.

References to “we,” “us,” “our,” the “Partnership” and “ETLP” shall mean Energy Transfer, LP 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 through ET Interstate and Panhandle. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger, CrossCountry, ETC MEP and ET Rover. Panhandle is the parent company of the Trunkline and Sea Robin transmission systems.

• Crude oil and NGLs transportation, 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 billionin exchange for a49.9%interest in the holding company that owns65%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

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$20.00per 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.

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 received1.5common 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. As referenced above, following the completion of the Sunoco Logistics Merger, ETLP deconsolidated Sunoco Logistics.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETLP indirectly owns a60%membership interest and ETP indirectly owns a40%membership interest, sold a49%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 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”).The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETLP continues to consolidate Dakota Access and ETCO subsequent to this transaction.Upon closing, ETLP and ETP collectively own a38.25%interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”), and MarEn Bakken Company owns36.75%and Phillips 66 owns25.00%in the Bakken Pipeline.

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Results of Operations

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

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section below titled “Segment Operating Results.” Total Segment Adjusted EBITDA, as presented below, is equal to the consolidated measure of Adjusted EBITDA, which is a non- GAAP 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.

Consolidated Results

	Six Months Ended June 30,
	2017			2016			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	317		$	328		$	(11	)
Interstate transportation and storage	527			570			(43		)
Midstream	732			561			171
Liquids transportation and services	578			447			131
Investment in ETP	530			594			(64		)
All other	230			282			(52		)
Total	2,914			2,782			132
Depreciation, depletion and amortization	(1,033		)	(966		)	(67		)
Interest expense, net	(659		)	(636		)	(23		)
Losses on interest rate derivatives	(20		)	(151		)	131
Non-cash unit-based compensation expense	(37		)	(38		)	1
Unrealized gains (losses) on commodity risk management activities	98			(81		)	179
Inventory valuation adjustments	2			106			(104		)
Adjusted EBITDA related to unconsolidated affiliates	(586		)	(471		)	(115		)
Equity in earnings of unconsolidated affiliates	96			195			(99		)
Other, net	65			41			24
Income before income tax (expense) benefit	840			781			59
Income tax (expense) benefit	(126		)	67			(193		)
Net income	$	714		$	848		$	(134	)

Upon the completion of the Sunoco Logistics Merger, the Partnership deconsolidated ETP (formerly Sunoco Logistics). The Investment in ETP segment for the six months ended June 30, 2017 includes consolidated results of Sunoco Logistics through the merger date in April 2017 and the Partnership’s equity method Investment in ETP for May and June 2017 due to its ownership of ETP Class E, Class G and Class K units. The Investment in ETP segment for the six months ended June 30, 2016 represents consolidated results of Sunoco Logistics.

Segment Adjusted EBITDA. Segment Adjusted EBITDA increased for the six months endedJune 30, 2017 compared to the same period last year primarily due to the Midstream and Liquids Transportation and Services segments. The increase in the Midstream segment was primarily due to (i) higher realized crude, NGL and natural gas prices, which resulted in an increase of $93 million in non-fee based margin, (ii) a $36 million increase in non-fee based margin due to volume increases in the Permian, partially

32

offset by declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, (iii) an increase of $24 million in fee-based margin due to minimum volume commitments in the South Texas region, as well as volume increases in the Permian and Northeast regions, partially offset by declines in South Texas, North Texas and the Mid-Continent/Panhandle regions, and (iv) an increase of $42 million in fee-based margin due to recent acquisitions, include PennTex. These increases in the Midstream segment were partially offset by an increase of $13 million in operating expenses primarily due to recent acquisitions and a $9 million increase in selling, general and administrative expenses due to impacts from capitalized overhead, shared services allocation and insurance allocation, as well as the impact of recent acquisitions. The increase in the Liquids Transportation and Services segment included an increase of $40 million in fractionation and refinery services margin, primarily due to higher NGL volumes from most major producing regions, and the remainder of the increase in the segment was primarily due to higher volumes on our NGL pipelines and fractionators. The decrease in the Intrastate Transportation and Storage segment was primarily due to a $30 million decrease from renegotiated transportation contract resulting in lower billed volumes and a $21 million decrease in storage margin due to the impacts of market price changes on storage gas and financial derivatives; these decreases were partially offset by higher realized gains from pipeline optimization activity due to more favorable market conditions. The decrease in the Interstate Transportation and Storage segment was primarily due to lack of customer demand driven by weak spreads and mild weather; in addition, contract restructuring resulted in a $14 million decrease in revenues on the Tiger pipeline. The decrease in the Investment in ETP segment was primarily due to the deconsolidation of ETP (formerly Sunoco Logistics) upon the closing of the Sunoco Logistics Merger. The decrease in the All Other segment was primarily due to increased 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 primarily from higher transaction-related expenses; a decrease of $27 million in Adjusted EBITDA related to our investment in PES; and a decrease of $38 million from the termination of management fees previously paid by ETE to the Partnership; partially offset by a one-time fee of $15 million received from a joint venture affiliate in the three months endedJune 30, 2017.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased for the six months endedJune 30, 2017 compared to the same period last year primarily due to additional depreciation from assets recently placed in service and recent acquisitions, offset by reduction due to the deconsolidation of Sunoco Logistics in connection with the Sunoco Logistics Merger.

Losses on Interest Rate Derivatives. Losses on interest rate derivatives during the 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. Unrealized gains and losses on commodity risk management activities include unrealized amounts that are included in cost of products sold.  These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are subtracted and the unrealized gains are added back to reconcile from total Segment Adjusted EBITDA to net income.  For the six months ended June 30, 2017 compared to the same period last year, the change in unrealized gains and losses on commodity risk management activities primarily reflected the following:

• in our intrastate transportation and other segment, $25 million related to our natural gas storage activities due to the movement in market price of the physical gas and financial derivatives used to hedge that gas, $5 million related to retained fuel sales and storage segment, $7 million related to natural gas sales and other;

• in our midstream segment, $19 million related to non-fee based margin;

• in our liquids transportation and services segment, $84 million related to liquids marketing activities; and

• in our all other segment, $35 million related to natural gas marketing activities.

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 of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” below.

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

Income Tax (Expense) Benefit. 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 millionduring the periods presented. For the six months ended June 30, 2017, the total impact of statutory rate changes was$113 million, including the$77 millionimpact 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.

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Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

	Six Months Ended June 30,
	2017			2016		Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	51		$	49	$	2
FEP	25			26		(1		)
PES	(6		)	1		(7		)
MEP	20			22		(2		)
HPC	12			15		(3		)
AmeriGas	2			17		(15		)
Sunoco LP	(124		)	38		(162		)
ETP	88			—		88
Other	28			27		1
Total equity in earnings of unconsolidated affiliates	$	96		$	195	$	(99	)
Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus	$	163		$	161	$	2
FEP	37			37		—
PES	16			21		(5		)
MEP	43			47		(4		)
HPC	27			30		(3		)
Sunoco LP	137			125		12
ETP	112			—		112
Other	51			50		1
Total Adjusted EBITDA related to unconsolidated affiliates	$	586		$	471	$	115
Distributions received from unconsolidated affiliates:
Citrus	$	63		$	62	$	1
FEP	10			30		(20		)
AmeriGas	6			6		—
MEP	93			39		54
HPC	13			25		(12		)
Sunoco LP	72			66		6
ETP	156			—		156
Other	34			27		7
Total distributions received from unconsolidated affiliates	$	447		$	255	$	192

⁽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.

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The Partnership’s critical accounting policies have not changed subsequent to those reported in its Annual Report on Form 10-K for the year ended December 31, 2016. The following information is provided to supplement the Form 10-K disclosures specifically related to impairment of long-lived assets and goodwill.

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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.

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

Item 3, Quantitative and Qualitative Disclosures About Market Risk, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

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

35

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

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)–15(f) or Rule 15d–15(f) of the Exchange Act) during the three months endedJune 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 the Partnership’s Form 10-K for the year ended December 31, 2016 and Note 10 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer, LP 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 millionand 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 the Partnership’s Annual Report on Form 10-K for the previous fiscal year ended December 31, 2016.

36

ITEM 6. EXHIBITS

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

Exhibit Number	Description
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.

37

SIGNATURE

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

		ENERGY TRANSFER, LP
		By:	SXL Acquisition Sub LLC,
			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)

38

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kelcy L. Warren, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy Transfer, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2017

/s/ Kelcy L. Warren

Kelcy L. Warren

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas E. Long, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy Transfer, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2017

/s/ Thomas E. Long

Thomas E. Long

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer, LP (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kelcy L. Warren, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: August 9, 2017

/s/ Kelcy L. Warren

Kelcy L. Warren

Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer, LP and furnished to the Securities and Exchange Commission upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer, LP (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Long, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: August 9, 2017

/s/ Thomas E. Long

Thomas E. Long

Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer, LP and furnished to the Securities and Exchange Commission upon request.

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Document And Entity Information	6 Months Ended
	Jun. 30, 2017 shares
Entity Information [Abstract]
Entity Registrant Name	Energy Transfer, LP
Entity Central Index Key	0001012569
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	0
Document Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2

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Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 209	$ 360
Accounts receivable, net	1,203	3,002
Accounts receivable from related companies	1,116	209
Inventories	653	1,712
Income Taxes Receivable, Current	148	128
Derivative assets	5	20
Other current assets	142	298
Total current assets	3,476	5,729
Property, plant and equipment	47,256	58,220
Accumulated depreciation and depletion	(6,809)	(7,303)
Property, plant and equipment, net	40,447	50,917
Advances to and investments in unconsolidated affiliates	11,585	4,280
Other non-current assets, net	628	672
Intangible assets, net	3,962	4,696
Goodwill	2,294	3,897
Total assets	62,392	70,191
Current liabilities:
Accounts payable	956	2,900
Accounts payable to related companies	229	43
Derivative liabilities	2	166
Accrued and other current liabilities	2,111	1,905
Current maturities of long-term debt	1,365	1,189
Total current liabilities	4,663	6,203
Long-term debt, less current maturities	24,968	31,741
Long-term notes payable – related company	0	250
Non-current derivative liabilities	201	76
Deferred income taxes	4,243	4,394
Other non-current liabilities	934	952
Commitments and contingencies
Series A Preferred Units	0	33
Redeemable noncontrolling interests	0	15
Equity:
Partners’ Capital	24,429	18,634
Limited Partners:
Accumulated other comprehensive income	7	8
Total partners’ capital	24,436	18,642
Noncontrolling interest	2,947	7,885
Total equity	27,383	26,527
Total liabilities and equity	$ 62,392	$ 70,191

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Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
REVENUES:
Natural gas sales	$ 1,022	$ 695	$ 2,034	$ 1,533
NGL sales	1,478	1,150	3,025	2,090
Crude sales	724	1,713	3,071	2,923
Gathering, transportation and other fees	982	1,045	2,006	2,005
Refined product sales	155	234	626	479
Other	377	452	871	740
Total revenues	4,738	5,289	11,633	9,770
COSTS AND EXPENSES:
Cost of products sold	3,130	3,630	8,322	6,598
Operating expenses	373	374	752	722
Depreciation, depletion and amortization	473	496	1,033	966
Selling, general and administrative	86	74	196	155
Total costs and expenses	4,062	4,574	10,303	8,441
OPERATING INCOME	676	715	1,330	1,329
OTHER INCOME (EXPENSE):
Interest expense, net	(320)	(317)	(659)	(636)
Equity in earnings of unconsolidated affiliates	23	119	96	195
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Other, net	67	27	93	44
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	421	463	840	781
Income tax expense (benefit)	71	(9)	126	(67)
NET INCOME	350	472	714	848
Less: Net income attributable to noncontrolling interest	89	102	129	167
Less: Comprehensive income attributable to noncontrolling interest	89	102	129	167
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	$ 261	$ 370	$ 585	$ 681

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Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 350	$ 472	$ 714	$ 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	0	0	0	(1)
Change in other comprehensive income from unconsolidated affiliates	(1)	(5)	(1)	(11)
Total other comprehensive income (loss)	(1)	4	(1)	(10)
Comprehensive income	349	476	713	838
Less: Comprehensive income attributable to noncontrolling interest	89	102	129	167
Less: Net income attributable to noncontrolling interest	89	102	129	167
Comprehensive income (loss) attributable to partners	$ 260	$ 374	$ 584	$ 671

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Consolidated Statement Of Equity - 6 months ended Jun. 30, 2017 - USD ($) $ in Millions	Total	Partner’s Capital	Accumulated Other Comprehensive Income	Noncontrolling Interest
Balance, December 31, 2016 at Dec. 31, 2016	$ 26,527	$ 18,634	$ 8	$ 7,885
Distributions to partners	889	(889)	0	0
Distributions to noncontrolling interest	(167)	0	0	167
Units issued for cash	885	885	0	0
Capital contributions from noncontrolling interest	1,432	0	0	1,432
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	(280)	(49)	0	(231)
Partners' Capital Account, Acquisitions	(2,769)	4,033	0	(6,802)
Sale of Bakken Pipeline interest	2,000	1,260	0	740
Other Comprehensive Income (Loss), Net of Tax	(1)	0	(1)	0
Other, net	(69)	30	0	39
Net income	714	585	0	129
Balance, June 30, 2017 at Jun. 30, 2017	$ 27,383	$ 24,429	$ 7	$ 2,947

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Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Statement of Cash Flows [Abstract]
Cash Divested from Deconsolidation	$ (75)	$ 0
OPERATING ACTIVITIES
Net income	714	848
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,033	966
Deferred income taxes	122	(79)
Amortization included in interest expense	(1)	(12)
Inventory valuation adjustments	2	(106)
Unit-based compensation expense	37	38
Distributions on unvested awards	(15)	(13)
Equity in earnings of unconsolidated affiliates	(96)	(195)
Distributions from unconsolidated affiliates	353	199
Other non-cash	(135)	(124)
Net change in operating assets and liabilities, net of effects of acquisition	(942)	(96)
Net cash provided by operating activities	1,072	1,426
INVESTING ACTIVITIES
Cash received from Bakken Pipeline Transaction	2,000	0
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction	0	2,200
Capital expenditures, excluding allowance for equity funds used during construction	(2,844)	(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	95	56
Proceeds from the sale of assets	23	7
Change in restricted cash	0	(2)
Other	(2)	(1)
Net cash used in investing activities	(1,549)	(1,225)
FINANCING ACTIVITIES
Proceeds from borrowings	11,330	7,811
Repayments of long-term debt	(10,953)	(7,514)
Proceeds from Related Party Debt		147
Repayments of Related Party Debt	(255)
Units issued for cash	885	408
Subsidiary units issued for cash	0	667
Capital contributions from noncontrolling interest	444	161
Distributions to partners	(889)	(1,813)
Distributions to noncontrolling interest	(167)	(209)
Payments for Repurchase of Preferred Stock and Preference Stock	(53)	0
Net cash provided by (used in) financing activities	326	(342)
Decrease in cash and cash equivalents	(151)	(141)
Cash and cash equivalents, beginning of period	360	527
Cash and cash equivalents, end of period	209	386
Cash paid for acquisition of a noncontrolling interest	(280)	0
Payments to Acquire Businesses, Net of Cash Acquired	(251)	0
Debt issuance costs	(20)	0
Proceeds from (Payments for) Other Financing Activities	$ 4	$ 0

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Operations And Organization

6 Months Ended

Jun. 30, 2017

Operations And Organization [Abstract]

Operations And Organization

ORGANIZATION AND BASIS OF PRESENTATION

Organization

Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. Energy Transfer, LP and its subsidiaries are collectively referred to herein as the “Partnership,” “we,” “us,” “our” or “ETLP.”

In April 2017, Energy Transfer Partners, L.P. merged with a subsidiary of Sunoco Logistics Partners L.P. (the “Sunoco Logistics Merger”), at which time it 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.” Following the completion of the Sunoco Logistics Merger, ETLP has no remaining publicly traded units outstanding. Additionally, subsequent to the Sunoco Logistics Merger, ETLP deconsolidated Sunoco Logistics 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 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.

• 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 a50%interest in FEP, which owns100%of the Fayetteville Express interstate natural gas pipeline.

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

• CrossCountry, which indirectly owns a50%interest in Citrus, which owns100%of the FGT interstate natural gas pipeline.

• ETC MEP, which directly owns a50%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.

Our financial statements reflect the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•liquids transportation and services;

•investment in ETP; and

•all other.

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in Energy Transfer Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2016. 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 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, Revenuefrom 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, 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.

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Cash And Cash Equivalents

6 Months Ended

Jun. 30, 2017

Cash and Cash Equivalents [Abstract]

Cash And Cash Equivalents

CASH AND CASH EQUIVALENTS

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

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

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

	Six Months Ended June 30,
	2017			2016
Accounts receivable	$	136		$	(471	)
Accounts receivable from related companies	(888		)	(129		)
Inventories	132			(157		)
Other current assets	86			(53		)
Other non-current assets, net	(147		)	8
Accounts payable	(49		)	509
Accounts payable to related companies	187			21
Accrued and other current liabilities	(408		)	(22		)
Other non-current liabilities	40			20
Derivative assets and liabilities, net	(31		)	178
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(942	)	$	(96	)

Non-cash investing and financing activities are as follows:

	Six Months Ended June 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,230	$	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	$	—

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Inventories

6 Months Ended

Jun. 30, 2017

Inventory, Gross [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:

	June 30, 2017		December 31, 2016
Natural gas and NGLs	$	449	$	699
Crude oil	—		683
Refined products	—		113
Spare parts and other	204		217
Total inventories	$	653	$	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.

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Advances to and Investments in Affiliates (Notes)

6 Months Ended

Jun. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Investments in and Advances to Affiliates, Schedule of Investments [Text Block]

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Upon the completion of the Sunoco Logistics Merger, the Partnership deconsolidated ETP (formerly Sunoco Logistics). The Partnership holds an equity method investment in ETP due to its ownership of ETP Class E, Class G and Class K units.

The Partnership previously had outstanding 8.9 million Class E Units, 90.7 million Class G Units and 101.5 million Class K Units, all of which were held by wholly-owned subsidiaries of the Partnership and were therefore eliminated in the Partnership’s consolidated financial statements. In connection with the Sunoco Logistics Merger, all of the Partnership’s outstanding Class E, Class G and Class K units were cancelled and converted into an equal number of newly created Class E, Class G and Class K units representing limited partner interests in ETP, with the same rights, preferences, privileges, duties and obligations as such classes had immediately prior to the Sunoco Logistics Merger, as described below. Consequently, the ETP Class E, Class G and Class K units are reflected as an equity method investment in ETP by the Partnership subsequent to the Sunoco Logistics Merger. The Partnership’s equity in earnings and cash distributions related to the Class E, Class G and Class K units is as follows: (i) the Class E Units are entitled to aggregate earnings allocation and cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, (ii) the Class G Units are entitled to earnings allocation equal to ETPs income or loss excluding any income or loss generated by ETP Holdco or its consolidated subsidiaries and aggregate cash distributions equal to 26% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year, and (iii) the Class K Units are entitled to aggregate earnings allocation and cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. The investment in ETP has been recorded in the Partnership’s balance sheet at the historical carrying value as of the date of the Sunoco Logistics Merger.

The following table presents aggregated selected income statement data for ETP and Citrus (on a 100% basis for all periods presented):

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
ETP
Revenue	$	6,576	$	5,289	$	13,471	$	9,770
Operating income	732		715		1,386		1,329
Net income	292		472		656		848
Citrus
Revenue	$	219	$	214	$	409	$	405
Operating income	135		132		240		241
Net income	59		56		101		98

The Partnership has other equity method investments which were not, individually or in the aggregate, significant to our consolidated financial statements.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2017

Fair Value Measurements [Abstract]

Fair Value Measurements

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 $27.55 billion and $26.37 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 endedJune 30, 2017, no transfers were made between any levels within the fair value hierarchy.

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	74			74			—
Crude – Futures	9			9			—
Total commodity derivatives	151			132			19
Total assets	$	151		$	132		$	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	(68		)	(68		)	—
Crude – Futures	(5		)	(5		)	—
Total commodity derivatives	(123		)	(108		)	(15		)
Total liabilities	$	(324	)	$	(108	)	$	(216	)

				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	)

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Debt Obligations

6 Months Ended

Jun. 30, 2017

Debt Disclosure [Abstract]

Debt Obligations

DEBT OBLIGATIONS

Credit Facilities and Commercial Paper

ETLP Credit Facility

The ETLP Credit Facility allows for borrowings of up to$3.75 billionand 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 billionETLP Credit Facility.As ofJune 30, 2017, the ETLP Credit Facility had$1.54 billionof outstanding borrowings, all of which was commercial paper.

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 billioncredit facility provides substantially all of the remaining capital necessary to complete the projects. As ofJune 30, 2017, $2.50 billionwas outstanding under this credit facility.

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”). As of June 30, 2017, the PennTex Revolving Credit Facility had$148 millionof 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 ofJune 30, 2017.

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Series A Preferred Units (Notes)

6 Months Ended

Jun. 30, 2017

Series A Preferred Units [Abstract]

Preferred Units [Text Block]

PREFERRED UNITS

In January 2017, Energy Transfer Partners, L.P. repurchased all of its1.9 millionoutstanding Preferred Units for cash in the aggregate amount of$53 million.

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Equity

6 Months Ended

Jun. 30, 2017

Partners' Capital Notes [Abstract]

Equity

EQUITY

In connection with the Sunoco Logistics 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.

Common Units

Upon the completion of the Sunoco Logistics Merger, the Partnership’s equity distribution program, distribution reinvestment program and equity incentive plans have been terminated.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETLP indirectly owns a60%membership interest and ETP indirectly owns a40%membership interest, sold a49%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 billionin cash.Bakken Pipeline Investments LLC indirectly owns a75%interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”).The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETLP continues to consolidate Dakota Access and ETCO subsequent to this transaction.Upon closing, ETLP and ETP collectively own a38.25%interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”), and MarEn Bakken Company owns36.75%and Phillips 66 owns25.00%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$20.00per 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.

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

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Income Taxes (Notes)

6 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

For the three and six months ended June 30, 2017, the Partnership’s income tax expenseincluded 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 millionduring 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.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

6 Months Ended

Jun. 30, 2017

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

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 billionof 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 its7.00%senior notes. The remaining outstanding7.00%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 millionprincipal amount of6.375%senior notes due 2023 issued by Sunoco LP, (ii)$800 millionprincipal amount of6.25%senior notes due 2021 issued by Sunoco LP and (iii)$2.035 billionaggregate 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.

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 through2034. 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	$	14	$	21	$	34	$	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 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 ofJune 30, 2017, Sunoco, Inc. is a defendant insixcases, 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.Fourof 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 of9sites 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 of9New 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 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 ETLP 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 ETLP against Enterprise that consisted of $319 millionin compensatory damages and$595 million in disgorgement to ETLP.  The jury also found that ETLP owed Enterprise approximately $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETLP and awarded ETLP $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 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.

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 ofJune 30, 2017andDecember 31, 2016, accruals of approximately$71 millionand$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.

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$900,000in 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 at27sites 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.

Noamounts have been recorded in ourJune 30, 2017orDecember 31, 2016consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Environmental Matters

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

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

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

In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying 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 millionfor the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 millionto 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 ofJune 30, 2017, Sunoco, Inc. had been named as a PRP at approximately49identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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

	June 30, 2017		December 31, 2016
Current	$	30	$	26
Non-current	275		283
Total environmental liabilities	$	305	$	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 thethree months ended June 30,2017and2016, Sunoco, Inc. recorded$8 millionand$8 million, respectively, of expenditures related to environmental cleanup programs. During thesix months ended June 30,2017and2016, Sunoco, Inc. recorded$10 millionand$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$200,000to 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.

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Derivative Assets And Liabilities

6 Months Ended

Jun. 30, 2017

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Price Risk Management Assets and Liabilities

DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

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

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

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

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

We use derivatives in our liquids 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.

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	(4,562,000	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	—		—	(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.

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
		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.

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	16		24		(13		)	(52		)
Interest rate derivatives	—		—		(201		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	143		362		(323		)	(662		)
Total derivatives	$	151	$	362	$	(324	)	$	(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)	16			24			(13		)	(52		)
Broker cleared derivative contracts	Other current assets	135			338			(110		)	(420		)
Total gross derivatives		151			362			(324		)	(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		$	30		$	20		$	(203	)	$	(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.

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	8			(48		)	(2		)	(43		)
Interest rate derivatives	Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Embedded derivatives	Other, net	—			(4		)	1			(4		)
Total		$	(2	)	$	(140	)	$	5		$	(214	)

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Related Party Transactions

6 Months Ended

Jun. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions

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 inNote 8.

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	$	42	$	133	$	160	$	207

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
ETP	762		—
Sunoco LP	179		96
PES	1		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	59		65
Total accounts receivable from related companies:	$	1,116	$	209
Accounts payable to related companies:
ETP	$	47	$	—
Sunoco LP	177		20
FGT	—		1
Lake Charles LNG	2		3
Other	3		19
Total accounts payable to related companies:	$	229	$	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	)

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Reportable Segments

6 Months Ended

Jun. 30, 2017

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

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;

•liquids transportation and services;

•investment in ETP; and

•all other.

As discussed in Note 1, Sunoco Logistics changed its name to ETP upon the completion of the Sunoco Logistics Merger. Accordingly, the reportable segment previously named “Investment in Sunoco Logistics” has been renamed “Investment in ETP.” For periods prior to the Sunoco Logistics Merger, this reportable segment reflects the consolidated results of Sunoco Logistics. For periods subsequent to the Sunoco Logistics Merger, this segment reflects the investments in ETP’s Class E, Class G and Class K units that continue to be held by the Partnership’s subsidiaries, which are accounted for under the equity method.

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 ETLP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETLP 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 ofJune 30, 2017, the Partnership’s interest in Sunoco LP common units consisted of43.5 millionunits, representing43.7%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 liquids transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in ETP 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.

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	640			690			1,205			1,217
Intersegment revenues	977			640			2,049			1,205
	1,617			1,330			3,254			2,422
Liquids transportation and services:
Revenues from external customers	1,391			1,099			2,899			1,928
Intersegment revenues	112			11			226			101
	1,503			1,110			3,125			2,029
Investment in ETP:
Revenues from external customers	991			2,250			4,176			3,979
Intersegment revenues	11			18			45			66
	1,002			2,268			4,221			4,045
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	(1,214		)	(905		)	(2,618		)	(1,883		)
Total revenues	$	4,738		$	5,289		$	11,633		$	9,770

	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
Liquids transportation and services	319			220			578			447
Investment in ETP	252			245			530			594
All other	107			180			230			282
Total	1,500			1,370			2,914			2,782
Depreciation, depletion and amortization	(473		)	(496		)	(1,033		)	(966		)
Interest expense, net	(320		)	(317		)	(659		)	(636		)
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Non-cash unit-based compensation expense	(14		)	(19		)	(37		)	(38		)
Unrealized gains (losses) on commodity risk management activities	34			(18		)	98			(81		)
Inventory valuation adjustments	—			132			2			106
Adjusted EBITDA related to unconsolidated affiliates	(347		)	(252		)	(586		)	(471		)
Equity in earnings of unconsolidated affiliates	23			119			96			195
Other, net	43			25			65			41
Income before income tax expense (benefit)	$	421		$	463		$	840		$	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		18,011
Liquids transportation and services	12,651		11,296
Investment in ETP	7,462		18,819
All other	5,757		6,068
Total assets	$	62,392	$	70,191

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Operations And Organization Accounting Policy (Policies)

6 Months Ended

Jun. 30, 2017

Accounting Policies [Abstract]

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

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

New Accounting Pronouncements, Policy [Policy Text Block]

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenuefrom 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, 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.

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Cash And Cash Equivalents (Tables)

6 Months Ended

Jun. 30, 2017

Cash and Cash Equivalents [Abstract]

Net Cash Provided By Operating Activities

	Six Months Ended June 30,
	2017			2016
Accounts receivable	$	136		$	(471	)
Accounts receivable from related companies	(888		)	(129		)
Inventories	132			(157		)
Other current assets	86			(53		)
Other non-current assets, net	(147		)	8
Accounts payable	(49		)	509
Accounts payable to related companies	187			21
Accrued and other current liabilities	(408		)	(22		)
Other non-current liabilities	40			20
Derivative assets and liabilities, net	(31		)	178
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(942	)	$	(96	)

Non-Cash Investing And Financing Activities

	Six Months Ended June 30,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,230	$	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	$	—

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Inventories (Tables)

6 Months Ended

Jun. 30, 2017

Inventory, Gross [Abstract]

Schedule Of Inventories

Inventories consisted of the following:

	June 30, 2017		December 31, 2016
Natural gas and NGLs	$	449	$	699
Crude oil	—		683
Refined products	—		113
Spare parts and other	204		217
Total inventories	$	653	$	1,712

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Advances to and Investments in Affiliates (Tables)

6 Months Ended

Jun. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

The following table presents aggregated selected income statement data for ETP and Citrus (on a 100% basis for all periods presented):

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
ETP
Revenue	$	6,576	$	5,289	$	13,471	$	9,770
Operating income	732		715		1,386		1,329
Net income	292		472		656		848
Citrus
Revenue	$	219	$	214	$	409	$	405
Operating income	135		132		240		241
Net income	59		56		101		98

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2017

Fair Value Measurements [Abstract]

Fair Value Of Assets And Liabilities Measured And Recorded On Recurring Basis

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	74			74			—
Crude – Futures	9			9			—
Total commodity derivatives	151			132			19
Total assets	$	151		$	132		$	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	(68		)	(68		)	—
Crude – Futures	(5		)	(5		)	—
Total commodity derivatives	(123		)	(108		)	(15		)
Total liabilities	$	(324	)	$	(108	)	$	(216	)

				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	)

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Equity (Tables)

6 Months Ended

Jun. 30, 2017

Accumulated Other Comprehensive Income

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

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables)

6 Months Ended

Jun. 30, 2017

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract]

Schedule of Rent Expense [Table Text Block]

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through2034. 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	$	14	$	21	$	34	$	39

Environmental Exit Costs by Cost [Table Text Block]

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	$	30	$	26
Non-current	275		283
Total environmental liabilities	$	305	$	309

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Derivative Assets And Liabilities (Tables)

6 Months Ended

Jun. 30, 2017

Derivative [Line Items]

Outstanding Commodity-Related Derivatives

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	(4,562,000	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) – Futures	—		—	(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 Swaps Outstanding

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
		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.

Fair Value Of Derivative Instruments

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	16		24		(13		)	(52		)
Interest rate derivatives	—		—		(201		)	(193		)
Embedded derivatives in Preferred Units	—		—		—			(1		)
	143		362		(323		)	(662		)
Total derivatives	$	151	$	362	$	(324	)	$	(666	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]

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)	16			24			(13		)	(52		)
Broker cleared derivative contracts	Other current assets	135			338			(110		)	(420		)
Total gross derivatives		151			362			(324		)	(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		$	30		$	20		$	(203	)	$	(324	)

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

	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

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

	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	8			(48		)	(2		)	(43		)
Interest rate derivatives	Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Embedded derivatives	Other, net	—			(4		)	1			(4		)
Total		$	(2	)	$	(140	)	$	5		$	(214	)

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions For Period Presented [Table Text Block]

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	$	42	$	133	$	160	$	207

Related Party Transactions [table text block]

	June 30, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	—	$	22
ETP	762		—
Sunoco LP	179		96
PES	1		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	59		65
Total accounts receivable from related companies:	$	1,116	$	209
Accounts payable to related companies:
ETP	$	47	$	—
Sunoco LP	177		20
FGT	—		1
Lake Charles LNG	2		3
Other	3		19
Total accounts payable to related companies:	$	229	$	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	)

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Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2017

Sales Revenue, Segment [Member]

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

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	640			690			1,205			1,217
Intersegment revenues	977			640			2,049			1,205
	1,617			1,330			3,254			2,422
Liquids transportation and services:
Revenues from external customers	1,391			1,099			2,899			1,928
Intersegment revenues	112			11			226			101
	1,503			1,110			3,125			2,029
Investment in ETP:
Revenues from external customers	991			2,250			4,176			3,979
Intersegment revenues	11			18			45			66
	1,002			2,268			4,221			4,045
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	(1,214		)	(905		)	(2,618		)	(1,883		)
Total revenues	$	4,738		$	5,289		$	11,633		$	9,770

Operating Segments [Member]

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	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
Liquids transportation and services	319			220			578			447
Investment in ETP	252			245			530			594
All other	107			180			230			282
Total	1,500			1,370			2,914			2,782
Depreciation, depletion and amortization	(473		)	(496		)	(1,033		)	(966		)
Interest expense, net	(320		)	(317		)	(659		)	(636		)
Losses on interest rate derivatives	(25		)	(81		)	(20		)	(151		)
Non-cash unit-based compensation expense	(14		)	(19		)	(37		)	(38		)
Unrealized gains (losses) on commodity risk management activities	34			(18		)	98			(81		)
Inventory valuation adjustments	—			132			2			106
Adjusted EBITDA related to unconsolidated affiliates	(347		)	(252		)	(586		)	(471		)
Equity in earnings of unconsolidated affiliates	23			119			96			195
Other, net	43			25			65			41
Income before income tax expense (benefit)	$	421		$	463		$	840		$	781

Assets Segments [Member]

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	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		18,011
Liquids transportation and services	12,651		11,296
Investment in ETP	7,462		18,819
All other	5,757		6,068
Total assets	$	62,392	$	70,191

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Operations And Organization Operations And Organization (Details)	6 Months Ended
	Jun. 30, 2017
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
MEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
Rover Pipeline LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	65.00%
Fayetteville Express Pipeline, LLC [Member] | FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Citrus [Member] | FGT
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%

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Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash and Cash Equivalents [Abstract]
Accounts receivable	$ 136	$ (471)
Accounts receivable from related companies	(888)	(129)
Inventories	132	(157)
Other current assets	86	(53)
Other non-current assets, net	(147)	8
Accounts payable	(49)	509
Accounts payable to related companies	187	21
Accrued and other current liabilities	(408)	(22)
Other non-current liabilities	40	20
Derivative assets and liabilities, net	(31)	178
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$ (942)	$ (96)

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Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,230	$ 861
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP	0	194
Net gains from subsidiary common unit issuances	0	14
NON-CASH FINANCING ACTIVITIES:
Capital Contributions from Noncontrolling Interest	$ 988	$ 0

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Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Inventory, Gross [Abstract]
Natural gas and NGLs	$ 449	$ 699
Crude oil	0	683
Refined products	0	113
Spare parts and other	204	217
Total inventories	$ 653	$ 1,712

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Advances to and Investments in Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Schedule of Equity Method Investments [Line Items]
Revenues	$ 4,738	$ 5,289	$ 11,633	$ 9,770
OPERATING INCOME	676	715	1,330	1,329
Net income	350	472	714	848
ETP [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	6,576	5,289	13,471	9,770
OPERATING INCOME	732	715	1,386	1,329
Net income	292	472	656	848
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	219	214	409	405
OPERATING INCOME	135	132	240	241
Net income	$ 59	$ 56	$ 101	$ 98

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Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Fair Value Measurements [Abstract]
Transfers between levels in fair value hierarchy	$ 0
Aggregate fair value of long-term debt	27,550	$ 33,850
Long-term Debt	$ 26,370	$ 32,930

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Fair Value Measurements Fair Value Heigharchy (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Derivative Liability, Fair Value, Gross Liability	$ (324)	$ (666)
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	151	362
Assets, Fair Value Disclosure, Recurring	151	362
Interest rate derivatives, Liabilities	(201)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	(123)	(472)
Liabilities, Fair Value Disclosure, Recurring	(324)	(666)
Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	132	355
Assets, Fair Value Disclosure, Recurring	132	355
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(108)	(464)
Liabilities, Fair Value Disclosure, Recurring	(108)	(464)
Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	19	7
Assets, Fair Value Disclosure, Recurring	19	7
Interest rate derivatives, Liabilities	(201)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(15)	(8)
Liabilities, Fair Value Disclosure, Recurring	(216)	(201)
Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Assets, Fair Value Disclosure, Recurring		0
Interest rate derivatives, Liabilities		0
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value		0
Liabilities, Fair Value Disclosure, Recurring		(1)
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	9	14
Price Risk Derivative Liabilities, at Fair Value	(9)	(11)
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	9	14
Price Risk Derivative Liabilities, at Fair Value	9	(11)
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	3	2
Price Risk Derivative Liabilities, at Fair Value	(2)	(3)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	1	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	2	2
Price Risk Derivative Liabilities, at Fair Value	2	(3)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	38	96
Price Risk Derivative Liabilities, at Fair Value	(25)	(149)
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	38	96
Price Risk Derivative Liabilities, at Fair Value	25	(149)
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	4	1
Price Risk Derivative Liabilities, at Fair Value	(1)
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	4	1
Price Risk Derivative Liabilities, at Fair Value	1
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	13	4
Price Risk Derivative Liabilities, at Fair Value	(12)	(5)
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	13	4
Price Risk Derivative Liabilities, at Fair Value	12	(5)
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		1
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	1	(1)
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		233
Price Risk Derivative Liabilities, at Fair Value	(68)	(273)
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		233
Price Risk Derivative Liabilities, at Fair Value	68	(273)
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0	1
Price Risk Derivative Liabilities, at Fair Value		(17)
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	0	1
Price Risk Derivative Liabilities, at Fair Value		(17)
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	9	9
Price Risk Derivative Liabilities, at Fair Value	(5)	(13)
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	9	9
Price Risk Derivative Liabilities, at Fair Value	5	(13)
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	0
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		$ 0

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Debt Obligations Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Repayments of Long-term Debt	$ 10,953	$ 7,514
Proceeds from Issuance of Long-term Debt	11,330	$ 7,811
ETLP [Member] | ETLP Credit Facility due November 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity	3,750
Long-term Line of Credit	1,540
Bakken Pipeline [Member] | Bakken Term Note [Member]
Line of Credit Facility, Maximum Borrowing Capacity	2,500
PennTex $275 million Revolving Credit Facility due December 2019 [Member] | PennTex [Member]
Line of Credit Facility, Current Borrowing Capacity	275
Long-term Line of Credit	148
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Long-term Line of Credit	$ 2,500

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Series A Preferred Units (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended	6 Months Ended
	Jan. 31, 2017	Jun. 30, 2017	Jun. 30, 2016
Payments for Repurchase of Preferred Stock and Preference Stock	$ 53	$ 53	$ 0
ETP Series A Preferred Units [Member]
Partners' Capital Account, Units, Redeemed	1.9

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Equity Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2017	Jun. 30, 2016	Feb. 01, 2017
Proceeds from Sale of Equity Method Investments		$ 0	$ 2,200
Net gains from subsidiary common unit issuances		0	14
Proceeds from Issuance of Common Limited Partners Units		885	$ 408
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		$ 2,000
PennTex [Member]
Sale of Stock, Price Per Share		$ 20.00
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross	$ 2,000
ETLP [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired				49.00%
Dakota Access and ETCOC [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Dakota Access and ETCOC [Member] | Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	75.00%
Bakken Pipeline [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	25.00%
Bakken Pipeline [Member] | ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	38.25%
Bakken Pipeline [Member] | MarEn Bakken Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	36.75%

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Equity AOCI (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Partners' Capital Notes [Abstract]
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

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Income Taxes (Details) $ in Millions	6 Months Ended
	Jun. 30, 2017 USD ($)
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ 77

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2012 USD ($)	Jun. 30, 2017 USD ($) sites	Jun. 30, 2016 USD ($)	Jun. 30, 2017 USD ($) sites	Jun. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Maximum lease expiration year				Dec. 31, 2034
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		$ 0		$ 0
Accrual for Environmental Loss Contingencies		$ 305,000,000		$ 305,000,000		$ 309,000,000
Sites where remediation operations are responsibility of third parties | sites		9		9
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		$ 595,000,000		$ 595,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		319,000,000		319,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		$ 536,000,000		$ 536,000,000
AmeriGas [Member]
Contingent Residual Support Agreement, Amount	$ 1,550,000,000
Debt Instrument, Interest Rate, Stated Percentage		7.00%		7.00%
Sunoco LP | 6.375% Senior Notes due April 2023 [Member]
Senior Notes		$ 800,000,000		$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.375%		6.375%
Sunoco LP | 6.25% Senior Notes due 2021 [Member]
Senior Notes		$ 800,000,000		$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.25%		6.25%
Sunoco LP | Term loan due 2019 [Member]
Senior Notes		$ 2,035,000,000		$ 2,035,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		6		6
Payments for Environmental Liabilities		$ 8,000,000	$ 8,000,000	$ 10,000,000	$ 14,000,000
Proposed Environmental Penalty		$ 200,000		$ 200,000
Sunoco, Inc. [Member] | Multidistrict Legislation [Member]
Loss Contingency, Pending Claims, Number		4		4
Sunoco [Member]
Sites where remediation operations are responsibility of third parties		49		49
Related To Deductibles [Member]
Loss Contingency Accrual		$ 71,000,000		$ 71,000,000		$ 77,000,000
Federal [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty		7,000,000		7,000,000
State and Local Jurisdiction [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty		$ 1,000,000		$ 1,000,000

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Rental expense	$ 14	$ 21	$ 34	$ 39

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Environmental Exit Cost [Line Items]
Current	$ 30	$ 26
Non-current	275	283
Total environmental liabilities	$ 305	$ 309

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Derivative Assets And Liabilities Outstanding Commodity Derivatives (Details)		6 Months Ended	12 Months Ended
		Jun. 30, 2017 barrels Megawatt bbl MMbtu	Dec. 31, 2016 barrels Megawatt bbl MMbtu
WTI Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
WTI Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | bbl		(1,569,000)	(617,000)
Natural Gas Liquids [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2017
Natural Gas Liquids [Member] | Forwards Swaps [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | bbl		(4,562,000)	(5,786,627)
Power [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt		(497,530)	(391,880)
Power [Member] | Forwards Swaps [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Power [Member] | Forwards Swaps [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2018	2018
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Power [Member] | Options - Calls [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt		(607,200)	(186,400)
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | Megawatt		(212,880)
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt			(109,564)
Power [Member] | Future [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Power [Member] | Future [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2018	2018
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | Megawatt		(364,000)	(50,400)
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		(39,250,000)	(52,652,500)
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Notional Volume		(32,440,000)	(36,370,000)
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume			(682,500)
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		(465,000)
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2019	2019
Natural Gas [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		(9,302,540)	(22,492,489)
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Long [Member]
Notional Volume		(32,440,000)	(36,370,000)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		(3,630,000)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume			(10,750,000)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Fair Value Hedging Derivatives [Member] | Short [Member]
Notional Volume		(32,440,000)	(36,370,000)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives	[1]	2017	2017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume	[1]	(33,112,500)	(2,242,500)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Minimum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Maximum [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2018	2018
Natural Gas [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume			(5,662,500)
Natural Gas [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		(39,900,000)
Natural Gas [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2018
Natural Gas [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		(11,500,000)	0
Natural Gas [Member] | Options - Puts [Member] | Minimum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017
Natural Gas [Member] | Options - Puts [Member] | Maximum [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2019
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2017
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | barrels		0	(2,240,000)

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

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Derivative Assets And Liabilities Outstanding Interest Rate Derivatives (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2017	Dec. 31, 2016
July 2017 [Member]
Notional Amount	[1]	$ 0	$ 500
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
July 2018 [Member]
Notional Amount	[1]	$ 300	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate
December 2018 [Member]
Notional Amount		$ 1,200	1,200
Type	[2]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
July 2019 [Member]
Notional Amount	[1]	$ 300	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate
July 2020 [Member]
Notional Amount	[1]	$ 400	0
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
March 2019 [Member]
Notional Amount		$ 300	$ 300
Type	[2]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%

[1] Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

[2] Floating rates are based on 3-month LIBOR.

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Derivative Assets And Liabilities Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Total derivatives assets	$ 151	$ 362
Total derivatives liabilities	(324)	(666)
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits)
Total derivatives assets	8	0
Total derivatives liabilities	1	4
Not Designated as Hedging Instrument [Member]
Total derivatives assets	143	362
Total derivatives liabilities	(323)	(662)
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits)
Total derivatives assets	127	338
Total derivatives liabilities	109	416
Not Designated as Hedging Instrument [Member] | Commodity derivatives
Total derivatives assets	16	24
Total derivatives liabilities	13	52
Not Designated as Hedging Instrument [Member] | Interest rate derivatives
Total derivatives assets	0	0
Total derivatives liabilities	201	193
Embedded Derivatives in Preferred Units [Member] | Not Designated as Hedging Instrument [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ 0	$ 1

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Derivative Assets And Liabilities Fair Value of Derivatives, Netting Basis (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 151	$ 362
Derivative Liability, Fair Value, Gross Liability	(324)	(666)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(11)	(4)
Derivative Liability, Fair Value, Amount Offset Against Collateral	11	4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(110)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	110	338
Derivative Asset, Fair Value, Net	30	20
Derivative Liability, Fair Value, Net	(203)	(324)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	201	194
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	16	24
Derivative Liability, Fair Value, Gross Liability	13	(52)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	135	338
Derivative Liability, Fair Value, Gross Liability	$ 110	$ (420)

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Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Recognized OCI On Derivatives (Effective Portion) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Commodity derivatives	$ 6	$ 21	$ 2	$ 17
Commodity Derivatives [Member]
Commodity derivatives	$ 6	$ 21	$ 2	$ 17

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Derivative Assets And Liabilities Partnership's Derivative Assets And Liabilities, Amount Of Gain/(Loss) Reclassified From AOCI Into Income (Effective Portion) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ 6	$ 21	$ 2	$ 17
Amount of Gain/(Loss) Recognized in Income on Derivatives	(2)	(140)	5	(214)
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	15	(7)	26	(16)
Commodity derivatives
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	6	21	2	17
Amount of Gain/(Loss) Recognized in Income on Derivatives	8	(48)	(2)	(43)
Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 0	$ (4)	$ 1	$ (4)

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Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Related Party Transactions [Abstract]
Affiliated revenues	$ 42	$ 133	$ 160	$ 207

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Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Total accounts receivable from related companies:	$ 1,116	$ 209
Total accounts payable to related companies:	229	43
Long-term notes payable – related companies	0	(250)
Net Related Party Receivable (Payable)	87	(163)
ETE
Total accounts receivable from related companies:	0	22
ETP [Member]
Total accounts receivable from related companies:	762	0
Total accounts payable to related companies:	47	0
Sunoco LP
Notes Receivable, Related Parties, Noncurrent	87	87
Total accounts receivable from related companies:	179	96
Total accounts payable to related companies:	177	20
PES
Total accounts receivable from related companies:	1	6
FGT
Total accounts receivable from related companies:	9	15
Total accounts payable to related companies:	0	1
Lake Charles LNG
Total accounts receivable from related companies:	1	4
Total accounts payable to related companies:	2	3
Trans-Pecos Pipeline, LLC
Total accounts receivable from related companies:	4	1
Comanche Trail Pipeline, LLC [Member]
Total accounts receivable from related companies:	1	0
Traverse Rover LLC [Member]
Total accounts receivable from related companies:	100	0
Other
Total accounts receivable from related companies:	59	65
Total accounts payable to related companies:	3	19
Phillips 66 Partners LP [Member]
Long-term notes payable – related companies	$ 0	$ (250)

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Reportable Segments Segment Revenues (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Segment Reporting Information [Line Items]
Revenues	$ 4,738	$ 5,289	$ 11,633	$ 9,770
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Revenues	753	541	1,569	1,099
Intrastate transportation and storage | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	699	428	1,467	874
Intrastate transportation and storage | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	54	113	102	225
Interstate transportation and storage
Segment Reporting Information [Line Items]
Revenues	207	234	442	493
Interstate transportation and storage | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	201	229	432	483
Interstate transportation and storage | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	6	5	10	10
Midstream
Segment Reporting Information [Line Items]
Revenues	1,617	1,330	3,254	2,422
Midstream | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	640	690	1,205	1,217
Midstream | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	977	640	2,049	1,205
Liquids transportation and services
Segment Reporting Information [Line Items]
Revenues	1,503	1,110	3,125	2,029
Liquids transportation and services | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	1,391	1,099	2,899	1,928
Liquids transportation and services | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	112	11	226	101
Investment in ETP
Segment Reporting Information [Line Items]
Revenues	1,002	2,268	4,221	4,045
Investment in ETP | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	991	2,250	4,176	3,979
Investment in ETP | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	11	18	45	66
All other
Segment Reporting Information [Line Items]
Revenues	870	711	1,640	1,565
All other | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	816	593	1,454	1,289
All other | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	54	118	186	276
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (1,214)	$ (905)	$ (2,618)	$ (1,883)

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Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,500	$ 1,370	$ 2,914	$ 2,782
Depreciation, depletion and amortization	(473)	(496)	(1,033)	(966)
Interest expense, net	(320)	(317)	(659)	(636)
Losses on interest rate derivatives	(25)	(81)	(20)	(151)
Non-cash unit-based compensation expense	(14)	(19)	(37)	(38)
Unrealized losses on commodity risk management activities	34	(18)	98	(81)
Inventory valuation adjustments	0	132	2	106
Adjusted EBITDA related to unconsolidated affiliates	(347)	(252)	(586)	(471)
Equity in earnings of unconsolidated affiliates	23	119	96	195
Other, net	43	25	65	41
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	421	463	840	781
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	148	149	317	328
Interstate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	262	278	527	570
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	412	298	732	561
Liquids transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	319	220	578	447
Investment in ETP
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	252	245	530	594
All other
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 107	$ 180	$ 230	$ 282

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Reportable Segments Segment Assets (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets	$ 62,392	$ 70,191
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Assets	7,129	5,164
Interstate transportation and storage
Segment Reporting Information [Line Items]
Assets	12,153	10,833
Midstream
Segment Reporting Information [Line Items]
Assets	17,240	18,011
Liquids transportation and services
Segment Reporting Information [Line Items]
Assets	12,651	11,296
Investment in ETP
Segment Reporting Information [Line Items]
Assets	7,462	18,819
All other
Segment Reporting Information [Line Items]
Assets	$ 5,757	$ 6,068

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Reportable Segments Reportable Segments Narrative (Details) - Sunoco LP shares in Millions	Jun. 30, 2017 shares
Investments in and Advances to Affiliates, Balance, Shares	43.5
Equity Method Investment, Ownership Percentage	43.70%