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 March 31, 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)

Energy Transfer Partners, L.P.

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant has submitted electronically 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

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	45
ITEM 4. CONTROLS AND PROCEDURES	47
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	48
ITEM 1A. RISK FACTORS	48
ITEM 6. EXHIBITS	49
SIGNATURE	50

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 “ETP”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations, or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected or expected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I – Item 1A. Risk Factors” in the Partnership’s 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)
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
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
ETP Credit Facility	ETP’s $3.75 billion revolving credit facility
ETP GP	Energy Transfer Partners GP, L.P., the general partner of ETP for the periods presented herein
ETP Holdco	ETP Holdco Corporation
ETP LLC	Energy Transfer Partners, L.L.C., the general partner of ETP GP for the periods presented herein
Exchange Act	Securities Exchange Act of 1934
FEP	Fayetteville Express Pipeline LLC

ii

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
LNG	liquefied natural gas
Lone Star	Lone Star NGL LLC
MEP	Midcontinent Express Pipeline LLC
MMBtu	million British thermal units
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 joint venture between subsidiaries of ETC OLP and 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.
Sunoco LP	Sunoco LP (previously named Susser Petroleum Partners, LP)
Transwestern	Transwestern Pipeline Company, LLC
Trunkline	Trunkline Gas Company, LLC, a subsidiary of Panhandle

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

iii

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	March 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	291		$	360
Accounts receivable, net	3,025			3,002
Accounts receivable from related companies	289			209
Inventories	1,546			1,712
Derivative assets	7			20
Other current assets	347			426
Total current assets	5,505			5,729
Property, plant and equipment	60,292			58,220
Accumulated depreciation and depletion	(7,760		)	(7,303		)
	52,532			50,917
Advances to and investments in unconsolidated affiliates	4,294			4,280
Other non-current assets, net	685			672
Intangible assets, net	5,506			4,696
Goodwill	3,915			3,897
Total assets	$	72,437		$	70,191

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

1

ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	March 31, 2017		December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,936	$	2,900
Accounts payable to related companies	188		43
Derivative liabilities	124		166
Accrued and other current liabilities	1,841		1,905
Current maturities of long-term debt	387		1,189
Total current liabilities	5,476		6,203
Long-term debt, less current maturities	31,648		31,741
Long-term notes payable – related company	—		250
Non-current derivative liabilities	72		76
Deferred income taxes	4,432		4,394
Other non-current liabilities	1,053		952
Commitments and contingencies
Series A Preferred Units	—		33
Redeemable noncontrolling interests	15		15
Equity:
General Partner	193		206
Limited Partners:
Common Unitholders	16,422		14,946
Class H Unitholder	3,483		3,480
Class I Unitholder	—		2
Accumulated other comprehensive income	8		8
Total partners’ capital	20,106		18,642
Noncontrolling interest	9,635		7,885
Total equity	29,741		26,527
Total liabilities and equity	$	72,437	$	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, except per unit data)

(unaudited)

	Three Months Ended March 31,
	2017			2016
REVENUES:
Natural gas sales	$	1,012		$	838
NGL sales	1,547			940
Crude sales	2,347			1,210
Gathering, transportation and other fees	1,024			960
Refined product sales	471			245
Other	494			288
Total revenues	6,895			4,481
COSTS AND EXPENSES:
Cost of products sold	5,192			2,968
Operating expenses	379			348
Depreciation, depletion and amortization	560			470
Selling, general and administrative	110			81
Total costs and expenses	6,241			3,867
OPERATING INCOME	654			614
OTHER INCOME (EXPENSE):
Interest expense, net	(339		)	(319		)
Equity in earnings of unconsolidated affiliates	73			76
Gains (losses) on interest rate derivatives	5			(70		)
Other, net	26			17
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	419			318
Income tax expense (benefit)	55			(58		)
NET INCOME	364			376
Less: Net income attributable to noncontrolling interest	40			65
NET INCOME ATTRIBUTABLE TO PARTNERS	324			311
General Partner’s interest in net income	206			297
Class H Unitholder’s interest in net income	98			79
Class I Unitholder’s interest in net income	—			2
Common Unitholders’ interest in net income (loss)	$	20		$	(67	)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$	0.02		$	(0.15	)
Diluted	$	0.02		$	(0.15	)

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 March 31,
	2017			2016
Net income	$	364		$	376
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2			2
Actuarial loss relating to pension and other postretirement benefit plans	(2		)	(9		)
Foreign currency translation adjustments	—			(1		)
Change in other comprehensive income from unconsolidated affiliates	—			(6		)
	—			(14		)
Comprehensive income	364			362
Less: Comprehensive income attributable to noncontrolling interest	40			65
Comprehensive income attributable to partners	$	324		$	297

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

4

ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2017

(Dollars in millions)

(unaudited)

				Limited Partners
	General Partner			Common Units			Class H Units			Class I Units			Accumulated Other Comprehensive Income		Noncontrolling Interest			Total
Balance, December 31, 2016	$	206		$	14,946		$	3,480		$	2		$	8	$	7,885		$	26,527
Distributions to partners	(219		)	(580		)	(95		)	(2		)	—		—			(896		)
Distributions to noncontrolling interest	—			—			—			—			—		(148		)	(148		)
Units issued for cash	—			826			—			—			—		—			826
Capital contributions from noncontrolling interest	—			—			—			—			—		1,094			1,094
Sale of Bakken Pipeline interest	—			1,260			—			—			—		740			2,000
Other, net	—			(50		)	—			—			—		24			(26		)
Net income	206			20			98			—			—		40			364
Balance, March 31, 2017	$	193		$	16,422		$	3,483		$	—		$	8	$	9,635		$	29,741

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

5

ENERGY TRANSFER, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Three Months Ended March 31,
	2017			2016
OPERATING ACTIVITIES
Net income	$	364		$	376
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	560			470
Deferred income taxes	54			(57		)
Amortization included in interest expense	(1		)	(7		)
Inventory valuation adjustments	(2		)	26
Unit-based compensation expense	23			19
Distributions on unvested awards	(8		)	(7		)
Equity in earnings of unconsolidated affiliates	(73		)	(76		)
Distributions from unconsolidated affiliates	82			84
Other non-cash	(52		)	(12		)
Net change in operating assets and liabilities, net of effects of acquisition	(15		)	144
Net cash provided by operating activities	932			960
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 all other acquisitions	(318		)	—
Capital expenditures, excluding allowance for equity funds used during construction	(1,384		)	(1,819		)
Contributions in aid of construction costs	6			10
Contributions to unconsolidated affiliates	(111		)	(31		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	90			51
Proceeds from the sale of assets	—			8
Change in restricted cash	—			(1		)
Other	(3		)	(3		)
Net cash provided by investing activities	280			415
FINANCING ACTIVITIES
Proceeds from borrowings	6,366			2,938
Repayments of long-term debt	(7,216		)	(3,914		)
Cash paid on affiliate notes	(250		)	(10		)
Units issued for cash	826			363
Subsidiary units issued for cash	—			301
Capital contributions from noncontrolling interest	106			132
Distributions to partners	(896		)	(897		)
Distributions to noncontrolling interest	(148		)	(100		)
Redemption of Series A Preferred Units	(53		)	—
Debt issuance costs	(19		)	—
Other	3			—
Net cash used in financing activities	(1,281		)	(1,187		)
Increase (decrease) in cash and cash equivalents	(69		)	188
Cash and cash equivalents, beginning of period	360			527
Cash and cash equivalents, end of period	$	291		$	715

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

6

ENERGY TRANSFER, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

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 “ETP.”

In April 2017, ETP merged with a subsidiary of Sunoco Logistics Partners L.P., at which time ETP 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.” Additional information related to the merger is included in Note 2 below. For purposes of maintaining clarity, the following references are used herein:

• References to “ETP” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the merger and 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 “Post-Merger 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, a Texas limited partnership and Regency, a Delaware limited partnership, 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 is 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, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:

• Transwestern, a Delaware limited liability company 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, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.

• ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.

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

• ETC MEP, a Delaware limited liability company that directly owns a 50% interest in MEP.

• ET Rover, a Delaware limited liability company.

• ETC Compression, LLC, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

• ETP Holdco, a Delaware limited liability company that 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.

• Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.

7

• PennTex, a publicly traded Delaware limited partnership that provides natural gas gathering and processing and residue gas and natural gas liquids transportation services to producers.

• Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP LLC, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETE transferred to ETP 21 million ETP common units. These operations were reported within the retail marketing segment. In connection with this transaction, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. Additionally, in March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business effective January 1, 2016.

Our financial statements reflect the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•liquids transportation and services;

•investment in Sunoco Logistics; 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 the Partnership’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

8

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. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

2. ACQUISITIONS AND CONTRIBUTION TRANSACTIONS

ETP and Sunoco Logistics Merger

In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction.Under the terms of the transaction, ETP unitholders received1.5common units of Sunoco Logistics for each common unit of ETP they owned.Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.Based on the ETP units outstanding at the closing of the merger, Sunoco Logistics issued approximately845 millionSunoco Logistics common units to ETP unitholders. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP 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 ETP 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 ETP at the effective time of the merger were cancelled.

9

Sunoco Logistics’ Permian Express Partners

In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately85%. Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of Sunoco Logistics and accordingly is reflected as a consolidated subsidiary of the Partnership. ExxonMobil Corp.’s interest is reflected as noncontrolling interest in the consolidated balance sheets. Sunoco Logistics' intangible assets increased by $547 million attributable to customer relationships that were recorded in connection with the formation of PEP.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a60%membership interest and Sunoco Logistics 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. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25%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.

3. CASH AND CASH EQUIVALENTS

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

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

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

	Three Months Ended March 31,
	2017			2016
Accounts receivable	$	(23	)	$	(9	)
Accounts receivable from related companies	(44		)	90
Inventories	168			(11		)
Other current assets	43			(99		)
Other non-current assets, net	(18		)	11
Accounts payable	(88		)	51
Accounts payable to related companies	120			(2		)
Accrued and other current liabilities	(139		)	4
Other non-current liabilities	(2		)	21
Derivative assets and liabilities, net	(32		)	88
Net change in operating assets and liabilities, net of effects of acquisition	$	(15	)	$	144

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Non-cash investing and financing activities are as follows:

	Three Months Ended March 31,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	832	$	826
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	—		5
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—

4. INVENTORIES

Inventories consisted of the following:

	March 31, 2017		December 31, 2016
Natural gas and NGLs	$	474	$	699
Crude oil	784		683
Refined products	86		113
Spare parts and other	202		217
Total inventories	$	1,546	$	1,712

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

5. FAIR VALUE MEASURES

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of March 31, 2017 was $33.09 billion and $32.04 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, interest rate derivatives and embedded derivatives in the Preferred Units 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. Derivatives related to the embedded derivatives in our preferred units at December 31, 2016 were valued using a binomial lattice model. The market inputs utilized in the model included credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the three months endedMarch 31, 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 March 31, 2017 and December 31, 2016 based on inputs used to derive their fair values:

				Fair Value Measurements at March 31, 2017
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	7		$	7		$	—		$	—
Fixed Swaps/Futures	30			30			—			—
Forward Physical Swaps	4			—			4			—
Power:
Futures	7			—			7			—
Options – Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	91			91			—			—
Crude – Futures	12			12			—			—
Total commodity derivatives	152			141			11			—
Total assets	$	152		$	141		$	11		$	—
Liabilities:
Interest rate derivatives	$	(188	)	$	—		$	(188	)	$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(10		)	(10		)	—			—
Swing Swaps IFERC	(1		)	—			(1		)	—
Fixed Swaps/Futures	(42		)	(42		)	—			—
Power:
Forwards	(8		)	—			(8		)	—
Natural Gas Liquids – Forwards/Swaps	(88		)	(88		)	—			—
Refined Products – Futures	(3		)	(3		)	—			—
Crude – Futures	(9		)	(9		)	—			—
Total commodity derivatives	(161		)	(152		)	(9		)	—
Total liabilities	$	(349	)	$	(152	)	$	(197	)	$	—

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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 the ETP 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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6. NET INCOME (LOSS) PER LIMITED PARTNER UNIT

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

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

	Three Months Ended March 31,
	2017			2016
Net income	$	364		$	376
Less: Income attributable to noncontrolling interest	40			65
Net income, net of noncontrolling interest	324			311
General Partner’s interest in net income	206			297
Class H Unitholder’s interest in net income	98			79
Class I Unitholder’s interest in net income	—			2
Common Unitholders’ interest in net income (loss)	20			(67		)
Additional earnings allocated to General Partner	(3		)	(3		)
Distributions on employee unit awards, net of allocation to General Partner	(7		)	(5		)
Net income (loss) available to Common Unitholders	$	10		$	(75	)
Weighted average Common Units – basic (1)	548.2			490.2
Basic net income (loss) per Common Unit	$	0.02		$	(0.15	)
Diluted net income (loss) available to Common Unitholders	$	10		$	(75	)
Weighted average Common Units – basic (1)	548.2			490.2
Dilutive effect of unvested employee unit awards	1.4			—
Weighted average Common Units – diluted (1)	549.6			490.2
Diluted net income (loss) per Common Unit	$	0.02		$	(0.15	)

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

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

7. DEBT OBLIGATIONS

ETP as Co-Obligor of Sunoco, Inc. Debt

In connection with previous transactions, ETP became a co-obligor on Sunoco, Inc.’s existing senior notes and debentures. Obligations totaling$400 millionmatured and were repaid in January 2017 and the remaining balance was$65 millionas ofMarch 31, 2017.

ETP Senior Notes

In January 2017, ETP issued$600 millionaggregate principal amount of4.20%senior notes due April 2027 and$900 millionaggregate principal amount of5.30%senior notes due April 2047.ETP used the$1.48 billionnet proceeds from the offering to refinance current maturities and to repay borrowings outstanding under the ETP Credit Facility.

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Credit Facilities and Commercial Paper

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to$3.75 billionand matures in November 2019. The indebtedness under the ETP 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, the Partnership initiated a commercial paper program under the borrowing limits established by the$3.75 billionETP Credit Facility.As ofMarch 31, 2017, the ETP Credit Facility had$389 millionof outstanding borrowings, all of which was commercial paper.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a$2.50 billionunsecured revolving credit facility (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to$3.25 billionunder certain conditions.As ofMarch 31, 2017, the Sunoco Logistics Credit Facility had$740 millionof outstanding borrowings, which included$128 millionof commercial paper.

In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility ("364-Day Credit Facility"), due to mature in December 2017, with a total lending capacity of$1.00 billion, including a$630 millionterm loan. The terms of the 364-Day Credit Facility are similar to those of the$2.50 billionSunoco Logistics Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. In connection with Sunoco Logistics’ merger with ETP, the 364-Day Credit Facility is expected to be terminated and repaid in the second quarter of 2017.

Bakken Credit Facility

In August 2016, ETP, Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The$2.50 billioncredit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects. As ofMarch 31, 2017, $2.50 billionwas outstanding under this credit facility.

PennTex Revolving Credit Facility

PennTex maintains a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”) that is expandable up to$400 millionunder certain conditions and matures in December 2019. As ofMarch 31, 2017, PennTex Revolving Credit Facility had$157 millionof outstanding borrowings.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as ofMarch 31, 2017.

8. SERIES A PREFERRED UNITS

In January 2017, ETP repurchased all of its1.9 millionoutstanding Series A Preferred Units for cash in the aggregate amount of$53 million.

9. EQUITY

ETP

The changes in outstanding common units during the three months ended March 31,2017 were as follows:

	Number of Units
Number of common units at December 31, 2016	529.9
Common units issued in connection with equity distribution agreements	5.4
Common units issued in connection with the distribution reinvestment plan	1.9
Common units issued to ETE in a private placement transaction	15.8
Number of common units at March 31, 2017	553.0

During the three months ended March 31,2017, the Partnership received proceeds of $194 million, net of $2 million commissions, from the issuance of common units pursuant to an equity distribution agreement, which were used for general

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partnership purposes. In connection with the merger of ETP and Sunoco Logistics in April 2017, the equity distribution agreement was terminated.

During the three months ended March 31,2017, distributions of $71 million were reinvested under the distribution reinvestment plan. In connection with the merger of ETP and Sunoco Logistics in April 2017, the distribution reinvestment plan was terminated.

Sunoco Logistics

There was no activity under the Sunoco Logistics equity distribution agreement for the three months endedMarch 31, 2017.

January 2017 Private Placement

In January 2017, the Partnership sold15.8 millionETP Common Units to ETE in a private placement transaction for gross proceeds of approximately$568 million.

Bakken Equity Sale

As discussed in Note 2, in February 2017, Bakken Holdings Company LLC sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, for $2.00 billion in cash. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. As a result of the sale, ETP recorded a deemed contribution of $1.26 billion during the three months ended March 31, 2017, representing the difference between proceeds from the sale and the proportionate share of the book value of the subsidiary, which was allocated to noncontrolling interest.

Quarterly Distributions of Available Cash

Following the merger of ETP and Sunoco Logistics in April 2017, we no longer have outstanding common units; therefore, we no longer declare quarterly distributions. The partnership agreement of Post-Merger ETP includes distribution provisions similar to those of ETP prior to the merger.

For the quarter endedDecember 31, 2016, ETP and Sunoco Logistics paid distributions onFebruary 14, 2017of$1.0550and$0.52, respectively, per common unit. For the quarter endedMarch 31, 2017, Post-Merger ETP declared a distribution of$0.5350per common unit, payable onMay 15, 2017to unitholders of record onMay 10, 2017.

PennTex Quarterly Distributions of Available Cash

PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of$0.2750per unit at the end of each quarter. Following are distributions declared and/or paid by PennTex subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 14, 2017	$	0.2950
March 31, 2017	May 5, 2017	May 12, 2017	0.2950

Accumulated Other Comprehensive Income

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

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

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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, ETP agreed to provide contingent residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchases. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its 7.00% senior notes, which reduced the remaining amount supported by ETP to $102 million. In March 2017, AmeriGas issued a notice of redemption for the remaining outstanding 7.00% senior notes, which senior notes will be redeemed in May 2017.

Guarantee of Sunoco LP Notes

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

NGL Pipeline Regulation

We have interests in NGL pipelines located in Texas and New Mexico. We commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

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 through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended March 31,
	2017		2016
Rental expense	$	20	$	18

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.

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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 gathering near a construction site on the Dakota Access pipeline project in North Dakota to protest the development of the pipeline project. Some of the protesters eventually 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 have moved to dismiss the lawsuit and Dakota Access has responded. The court’s decision is still pending.

In the meantime, 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. As explained below, 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 challenging the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claiming 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 moved to intervene in the case and that motion was granted by the Court. 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 Department of Justice, and the Department of the Interior released a joint statement stating 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 District Court. The U.S. District Court denied the emergency motion for an injunction pending the appeal. 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 statues 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 construction. 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. The CRST appealed and requested an injunction pending appeal in both the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. CRST has filed a motion with the D.C. Circuit for the purpose of voluntarily seeking dismissal of its appeal of its claims related to religious rights.

The SRST and the CRST have sought leave to amend their complaints to incorporate their religious freedom and other claims and have moved for summary judgment on their claims against the government based on treaty rights and the National Environmental Policy Act. Dakota Access has also moved for summary judgment with respect to these claims. The district court is still considering these motions. Briefing is ongoing.

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In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits in an effort to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST.

Construction of the pipeline is now complete. 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.

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 included are governmental authorities. The plaintiffs primarily assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As ofMarch 31, 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. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. All parties agreed to participate in global settlement discussions in a global mediation forum before Hon. Garrett Brown (Ret.), a Judicial Arbitration Mediation Service mediator. The remaining portion of the New Jersey case remains in the multidistrict litigation. Sunoco, Inc. and Sunoco, Inc. (R&M) participated in mediation with Judge Brown on November 2 through November 3, 2016 and on November 30, 2016. 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. Management believes that 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 does not believe that any such adverse determination would 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 Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal. 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. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ filed their Answering Brief on July 29, 2016. On August 31, 2016, Dieckman filed his Reply Brief. Oral argument was held on November 16, 2016 before the Delaware Supreme Court. On January 20, 2017, The Delaware Supreme Court issued an order reversing the judgment of the Court of Chancery

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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.

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

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise has filed a notice of appeal with the Texas Court of Appeals, and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. The Court of Appeals is taking the briefs under advisement. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.

Sunoco Logistics Merger Litigation

Between January 6, 2017 and February 8, 2017, seven purported ETP common unitholders (“Plaintiffs”) separately filed seven putative unitholder class action lawsuits challenging the merger and the disclosures made in connection with the merger. Since then, two of the Plaintiffs have non-suited their claims. The lawsuits remaining 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”). The Duany Lawsuit and Epstein Lawsuit are filed against ETP, ETP GP, ETP GP, LLC, ETE, and the members of the ETP Board. The Shure Lawsuit and Verlin Lawsuit are filed against ETP, ETP GP, the members of the ETP Board, ETE, Sunoco Logistics, and Sunoco Logistics GP. The Sgnilek Lawsuit is filed against ETP, ETP GP, ETP GP LLC, ETE, the members of the ETP Board, Sunoco Logistics and Sunoco Logistics GP (collectively “Defendants”).

Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. According to Plaintiffs, the preliminary joint proxy statement/prospectus is allegedly misleading because, among other things, it fails to disclose certain information concerning, in general, (a) the background and process that led to the merger; (b) ETE’s, ETP’s, and Sunoco Logistics’ financial projections; (c) the financial analysis and fairness opinion provided by Barclays; and (d) alleged conflicts of interest concerning Barclays, ETE, and certain officers and directors of ETP and ETE. Based on these allegations, and in general, 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 GP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Logistics GP 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.

Defendants’ dates to answer, move to dismiss, or otherwise respond to the Lawsuits have not yet been set. Defendants cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this quarterly report, nor can Defendants predict the amount of time and expense that will be required to resolve such litigation. Defendants believe the Lawsuits are without merit and intend to defend vigorously against the Lawsuits and any other actions challenging the merger.

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Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of March 31, 2017 and December 31, 2016, accruals of approximately $94 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

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

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

Environmental Matters

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

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.

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.

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

• Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of March 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law.

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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.

	March 31, 2017		December 31, 2016
Current	$	28	$	26
Non-current	288		283
Total environmental liabilities	$	316	$	309

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

During the three months ended March 31,2017 and 2016, Sunoco, Inc. recorded $2 million and $6 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 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

In September 2016, EPA issued an NOV related to well monitoring procedures at Sunoco Logistics’ Inkster terminal located near Detroit, Michigan. Penalties of approximately $0.1 million were assessed in connection with the NOV, which Sunoco Logistics paid in March 2017, to close out this matter. 

In December 2016, Sunoco Logistics received multiple NOVs from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016.  Sunoco Logistics also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC.  These actions propose penalties in excess of $0.1 million, and Sunoco Logistics is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows, or financial position.

Our operations are also subject to the requirements of the 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

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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.

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.

Sunoco Logistics utilizes 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:

	March 31, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	80,000		2017	(682,500	)	2017
Basis Swaps IFERC/NYMEX(1)	8,372,500		2017	2,242,500		2017
Power (Megawatt):
Forwards	225,480		2017-2018	391,880		2017-2018
Futures	(58,000	)	2017-2018	109,564		2017-2018
Options – Puts	67,200		2017	(50,400	)	2017
Options – Calls	447,200		2017	186,400		2017
Crude (Bbls) – Futures	(1,418,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(5,247,500	)	2017-2018	10,750,000		2017-2018
Swing Swaps IFERC	(12,185,000	)	2017	(5,662,500	)	2017
Fixed Swaps/Futures	(51,102,500	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	16,763,209		2017	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(1,827,400	)	2017	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(1,217,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(13,877,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(13,877,500	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	13,877,500		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
		March 31, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	500	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200
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
	March 31, 2017		December 31, 2016		March 31, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	—	$	(2	)	$	(4	)
	—		—		(2		)	(4		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	139		338		(145		)	(416		)
Commodity derivatives	13		24		(14		)	(52		)
Interest rate derivatives	—		—		(188		)	(193		)
Embedded derivatives in ETP Preferred Units	—		—		—			(1		)
	152		362		(347		)	(662		)
Total derivatives	$	152	$	362	$	(349	)	$	(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	March 31, 2017			December 31, 2016			March 31, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(188	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	13			24			(14		)	(52		)
Broker cleared derivative contracts	Other current assets	139			338			(147		)	(420		)
Total gross derivatives		152			362			(349		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(6		)	(4		)	6			4
Payments on margin deposit	Other current assets	(133		)	(338		)	133			338
Total net derivatives		$	13		$	20		$	(210	)	$	(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 March 31,
		2017			2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(4	)	$	(4	)
Total		$	(4	)	$	(4	)

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	11		$	(9	)
Commodity derivatives – Non-trading	Cost of products sold	(10		)	5
Interest rate derivatives	Gains (losses) on interest rate derivatives	5			(70		)
Embedded derivatives	Other, net	1			—
Total		$	7		$	(74	)

12. RELATED PARTY TRANSACTIONS

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 have subsequently expired.

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 March 31,
	2017		2016
Affiliated revenues	$	118	$	74

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

	March 31, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	3	$	22
Sunoco LP	200		96
PES	8		6
FGT	17		15
Lake Charles LNG	3		4
Trans-Pecos Pipeline, LLC	1		1
Comanche Trail Pipeline, LLC	1		—
Other	56		65
Total accounts receivable from related companies:	$	289	$	209
Accounts payable to related companies:
Sunoco LP	$	168	$	20
FGT	—		1
Lake Charles LNG	3		3
Other	17		19
Total accounts payable to related companies:	$	188	$	43

	March 31, 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 currently reflect the following reportable segments, which conduct their business in the United States, as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•liquids transportation and services;

•investment in Sunoco Logistics; and

•all other.

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 ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of March 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.7% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.

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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 Sunoco Logistics 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 March 31,
	2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	768		$	446
Intersegment revenues	48			112
	816			558
Interstate transportation and storage:
Revenues from external customers	231			254
Intersegment revenues	4			5
	235			259
Midstream:
Revenues from external customers	565			527
Intersegment revenues	1,072			565
	1,637			1,092
Liquids transportation and services:
Revenues from external customers	1,508			829
Intersegment revenues	114			90
	1,622			919
Investment in Sunoco Logistics:
Revenues from external customers	3,185			1,729
Intersegment revenues	34			48
	3,219			1,777
All other:
Revenues from external customers	638			696
Intersegment revenues	132			158
	770			854
Eliminations	(1,404		)	(978		)
Total revenues	$	6,895		$	4,481

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	Three Months Ended March 31,
	2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	169		$	179
Interstate transportation and storage	265			292
Midstream	320			263
Liquids transportation and services	259			227
Investment in Sunoco Logistics	278			349
All other	123			102
Total	1,414			1,412
Depreciation, depletion and amortization	(560		)	(470		)
Interest expense, net	(339		)	(319		)
Gains (losses) on interest rate derivatives	5			(70		)
Non-cash unit-based compensation expense	(23		)	(19		)
Unrealized gains (losses) on commodity risk management activities	64			(63		)
Inventory valuation adjustments	2			(26		)
Adjusted EBITDA related to unconsolidated affiliates	(239		)	(219		)
Equity in earnings of unconsolidated affiliates	73			76
Other, net	22			16
Income before income tax expense (benefit)	$	419		$	318

	March 31, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	4,801	$	5,164
Interstate transportation and storage	10,066		10,833
Midstream	18,366		18,011
Liquids transportation and services	12,672		11,296
Investment in Sunoco Logistics	19,425		18,819
All other	7,107		6,068
Total assets	$	72,437	$	70,191

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

AND RESULTS OF OPERATIONS

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

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; (ii) our 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 our Annual Report on Form 10-K for the year ended December 31, 2016.

References to “we,” “us,” “our,” the “Partnership” and “ETP” 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.

• Liquids operations, including NGL transportation, storage and fractionation services.

• Crude oil, NGLs and refined product transportation, terminalling services and acquisition and marketing activities through Sunoco Logistics.

RECENT DEVELOPMENTS

ETP and Sunoco Logistics Merger

In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction.Under the terms of the transaction, ETP unitholders received1.5common units of Sunoco Logistics for each common unit of ETP 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.

Sunoco Logistics’ Permian Express Partners

In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately85%. Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of Sunoco Logistics and accordingly is reflected as a consolidated subsidiary of the Partnership. ExxonMobil Corp.’s interest is reflected as noncontrolling interest in the consolidated balance sheets.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a60%membership interest and Sunoco Logistics 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. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25%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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Series A Preferred Units Redemption

In January 2017, ETP repurchased all of its1.9 millionoutstanding Series A Preferred Units for cash in the aggregate amount of$53 million.

32

Results of Operations

Consolidated Results

	Three Months Ended March 31,
	2017			2016			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	169		$	179		$	(10	)
Interstate transportation and storage	265			292			(27		)
Midstream	320			263			57
Liquids transportation and services	259			227			32
Investment in Sunoco Logistics	278			349			(71		)
All other	123			102			21
Total	1,414			1,412			2
Depreciation, depletion and amortization	(560		)	(470		)	(90		)
Interest expense, net	(339		)	(319		)	(20		)
Gains (losses) on interest rate derivatives	5			(70		)	75
Non-cash unit-based compensation expense	(23		)	(19		)	(4		)
Unrealized gains (losses) on commodity risk management activities	64			(63		)	127
Inventory valuation adjustments	2			(26		)	28
Adjusted EBITDA related to unconsolidated affiliates	(239		)	(219		)	(20		)
Equity in earnings of unconsolidated affiliates	73			76			(3		)
Other, net	22			16			6
Income before income tax (expense) benefit	419			318			101
Income tax (expense) benefit	(55		)	58			(113		)
Net income	$	364		$	376		$	(12	)

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased for the three months endedMarch 31, 2017 compared to the same period last year primarily due to additional depreciation from assets recently placed in service and recent acquisitions.

Gains (Losses) on Interest Rate Derivatives. The change in gains (losses) on interest rate derivatives for the three months ended March 31, 2017 compared to the same period last year was primarily due to the recognition of $70 million of losses in the prior period. Losses on interest rate derivatives during the three months ended March 31, 2016 were primarily attributable to the impact on our forward starting swap locks from the downward shift in the forward LIBOR curve.

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

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco Logistics’ 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” and “Segment Operation Results” below.

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

Income Tax (Expense) Benefit. For the three months endedMarch 31, 2017 compared to the same period last year, the Partnership recorded higher income tax expense primarily due to higher earnings among the Partnership’s consolidated corporate subsidiaries. In addition, income tax benefit for the three months ended March 31, 2016 also reflected a $20 million net state tax benefit attributable to statutory state rate changes resulting from the contribution by ETP to Sunoco LP of its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business.

33

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

	Three Months Ended March 31,
	2017			2016			Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	21		$	21		$	—
FEP	12			14			(2		)
PES	14			(6		)	20
MEP	10			11			(1		)
HPC	7			8			(1		)
AmeriGas	9			(2		)	11
Sunoco LP	(14		)	15			(29		)
Other	14			15			(1		)
Total equity in earnings of unconsolidated affiliates	$	73		$	76		$	(3	)
Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus	$	75		$	74		$	1
FEP	18			19			(1		)
PES	26			4			22
MEP	22			24			(2		)
HPC	15			15			—
Sunoco LP	54			57			(3		)
Other	29			26			3
Total Adjusted EBITDA related to unconsolidated affiliates	$	239		$	219		$	20
Distributions received from unconsolidated affiliates:
Citrus	$	41		$	35		$	6
FEP	—			17			(17		)
AmeriGas	3			3			—
MEP	73			21			52
HPC	—			12			(12		)
Sunoco LP	35			30			5
Other	20			17			3
Total distributions received from unconsolidated affiliates	$	172		$	135		$	37

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

Segment Operating Results

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

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

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

34

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

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

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

Intrastate Transportation and Storage

	Three Months Ended March 31,
	2017			2016			Change
Natural gas transported (MMBtu/d)	7,807,045			8,229,972			(422,927		)
Revenues	$	816		$	558		$	258
Cost of products sold	634			393			241
Gross margin	182			165			17
Unrealized losses on commodity risk management activities	15			38			(23		)
Operating expenses, excluding non-cash compensation expense	(38		)	(33		)	(5		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(6		)	(6		)	—
Adjusted EBITDA related to unconsolidated affiliates	16			15			1
Segment Adjusted EBITDA	$	169		$	179		$	(10	)

Volumes. For the three months endedMarch 31, 2017 compared to the same period last year, transported volumes decreased primarily due to lower production volumes in the Barnett Shale region, partially offset by increased volumes related to significant new long-term transportation contracts, as well as the addition of a new short haul transport pipeline delivering volumes into our Houston Pipeline system.

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

	Three Months Ended March 31,
	2017		2016			Change
Transportation fees	$	124	$	134		$	(10	)
Natural gas sales and other	34		23			11
Retained fuel revenues	16		10			6
Storage margin, including fees	8		(2		)	10
Total gross margin	$	182	$	165		$	17

Segment Adjusted EBITDA. For the three months endedMarch 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:

• a decrease of $10 million in transportation fees due to renegotiated contracts resulting in lower demand volumes beginning in the second quarter of 2016 on our ET Fuel pipeline, partially offset by an increase of $5 million due to fees from renegotiated and newly initiated fixed fee contracts primarily on our Houston Pipeline system;

• a decrease of $8 million in storage margin (excluding net changes in unrealized amounts of $18 million related to fair value inventory adjustments and unrealized gains and losses on derivatives), as discussed below; and

• an increase of $5 million in operating expenses primarily due to higher outside services labor costs and compression fuel expenses; partially offset by

35

• an increase of $7 million in natural gas sales and other (excluding changes in unrealized gains of $4 million) primarily due to higher realized gains from the buying and selling of gas along our system; and

• an increase of $5 million in retained fuels (excluding changes in unrealized gains of $1 million) primarily due to higher market prices. The average spot price at the Houston Ship Channel location increased 56% for the quarter ended March 31, 2017 compared to the same period last year.

Storage margin was comprised of the following:

	Three Months Ended March 31,
	2017			2016			Change
Withdrawals from storage natural gas inventory (MMBtu)	23,092,500			20,995,000			2,097,500
Realized margin on natural gas inventory transactions	$	19		$	28		$	(9	)
Fair value inventory adjustments	(36		)	17			(53		)
Unrealized (gains) losses on derivatives	18			(53		)	71
Margin recognized on natural gas inventory, including related derivatives	1			(8		)	9
Revenues from fee-based storage	7			6			1
Total storage margin	$	8		$	(2	)	$	10

The changes in storage margin were due primarily to the timing of the settlement of related derivative hedging contracts.

Interstate Transportation and Storage

	Three Months Ended March 31,
	2017			2016			Change
Natural gas transported (MMBtu/d)	5,655,558			5,835,046			(179,488		)
Natural gas sold (MMBtu/d)	16,905			17,177			(272		)
Revenues	$	235		$	259		$	(24	)
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(74		)	(72		)	(2		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(12		)	(12		)	—
Adjusted EBITDA related to unconsolidated affiliates	115			117			(2		)
Other	1			—			1
Segment Adjusted EBITDA	$	265		$	292		$	(27	)

Volumes. For the three months ended March 31, 2017 compared to the same period last year, transported volumes decreased primarily due to mild weather; in particular, volumes on the Transwestern pipeline decreased by 64,827 MMBtu/d. In addition, volumes on the Sea Robin pipeline decreased 37,075 MMBtu/d due to producer maintenance and production declines.

Segment Adjusted EBITDA. For the three months ended March 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to decreases in revenues of $12 million on the Tiger pipeline due to contract restructuring, $10 million on the Panhandle and Trunkline pipelines due to weak spreads and mild weather, and $2 million on the Sea Robin pipeline due to producer maintenance and production declines.

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Midstream

	Three Months Ended March 31,
	2017			2016			Change
Gathered volumes (MMBtu/d)	10,231,895			9,851,105			380,790
NGLs produced (Bbls/d)	445,004			430,973			14,031
Equity NGLs (Bbls/d)	25,521			29,533			(4,012		)
Revenues	$	1,637		$	1,092		$	545
Cost of products sold	1,124			678			446
Gross margin	513			414			99
Unrealized gains on commodity risk management activities	(16		)	—			(16		)
Operating expenses, excluding non-cash compensation expense	(161		)	(145		)	(16		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(23		)	(12		)	(11		)
Adjusted EBITDA related to unconsolidated affiliates	7			6			1
Segment Adjusted EBITDA	$	320		$	263		$	57

Volumes. Gathered volumes and NGL production increased during the three months endedMarch 31, 2017 compared to the same period last year primarily due to recent acquisitions, including PennTex, and gains in the Permian and Northeast regions, partially offset by basin declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions.

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

	Three Months Ended March 31,
	2017		2016		Change
Gathering and processing fee-based revenues	$	408	$	382	$	26
Non fee-based contracts and processing	105		32		73
Total gross margin	$	513	$	414	$	99

Segment Adjusted EBITDA. For the three months ended March 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:

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

• an increase of $17 million in non-fee based margin due to gains in the Permian, partially offset by declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions;

• an increase of $13 million in fee based revenue due to growth in the Permian, Northeast and North Louisiana, including recent acquisitions, offset by declines in South Texas, North Texas and the Mid-Continent/Panhandle regions; and

• an increase of $13 million in fee based revenue due to the PennTex acquisition; partially offset by

• a decrease of $5 million (excluding unrealized gains of $16 million) in non-fee based margin due to higher benefit from settled derivatives used to hedge commodity margins;

• an increase of $16 million in operating expenses primarily due to recent acquisitions, including PennTex; and

• an increase of $11 million in general and administrative expenses primarily due to a decrease of $4 million in capitalized overhead, a $3 million increase in shared services allocation, a $2 million increase in insurance allocation, and $2 million additional costs from the PennTex acquisition.

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Liquids Transportation and Services

	Three Months Ended March 31,
	2017			2016			Change
Crude/NGL transportation volumes (Bbls/d)	739,982			537,251			202,731
NGL fractionation volumes (Bbls/d)	433,473			362,906			70,567
Revenues	$	1,622		$	919		$	703
Cost of products sold	1,275			661			614
Gross margin	347			258			89
Unrealized (gains) losses on commodity risk management activities	(26		)	9			(35		)
Operating expenses, excluding non-cash compensation expense	(56		)	(37		)	(19		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(7		)	(5		)	(2		)
Adjusted EBITDA related to unconsolidated affiliates	1			2			(1		)
Segment Adjusted EBITDA	$	259		$	227		$	32

Volumes. For the three months endedMarch 31, 2017 compared to the same period last year, NGL transportation volumes increased in most major producing regions, including the Permian, North Texas, Louisiana and the Eagle Ford. Additionally, our Bayou Bridge crude pipeline, originating in Nederland and delivering into Lake Charles, began transporting volumes in April 2016.

Average daily fractionated volumes increased for the three months endedMarch 31, 2017 compared to the same period last year primarily due to the commissioning of our fourth fractionator at Mont Belvieu, Texas, in October 2016, which has a capacity of 120,000 Bbls/d, as well as increased producer volumes as mentioned above.

Gross Margin. The components of our liquids transportation and services segment gross margin were as follows:

	Three Months Ended March 31,
	2017		2016		Change
Transportation margin	$	145	$	108	$	37
Processing and fractionation margin	121		100		21
Storage margin	57		49		8
Other margin	24		1		23
Total gross margin	$	347	$	258	$	89

Segment Adjusted EBITDA. For the three months endedMarch 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our liquids transportation and services segment increased due to the net impact of the following:

• an increase of $37 million in transportation fees due to higher NGL and crude transport volumes;

• an increase of $17 million in processing and fractionation margin (excluding changes in unrealized gains of $4 million) primarily due to higher NGL volumes from most major producing regions, as noted above; and

• an increase of $8 million in storage margin primarily due to increased volumes from our Mont Belvieu fractionators; partially offset by

• a decrease of $8 million in other margin (excluding changes in unrealized gains of $31 million) primarily due to the timing of the recognition of margin from optimization activities;

• an increase of $19 million in operating expenses primarily due to increased costs associated with our fourth fractionator at Mont Belvieu and new pipelines placed in service; and

• an increase of $2 million in general and administrative expenses due to lower capitalized overhead as a result of reduced capital spending.

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Investment in Sunoco Logistics

	Three Months Ended March 31,
	2017			2016			Change
Revenues	$	3,219		$	1,777		$	1,442
Cost of products sold	2,889			1,439			1,450
Gross margin	330			338			(8		)
Unrealized (gains) losses on commodity risk management activities	(24		)	13			(37		)
Operating expenses, excluding non-cash compensation expense	(18		)	(21		)	3
Selling, general and administrative expenses, excluding non-cash compensation expense	(31		)	(23		)	(8		)
Inventory valuation adjustments	(2		)	26			(28		)
Adjusted EBITDA related to unconsolidated affiliates	20			16			4
Other	3			—			3
Segment Adjusted EBITDA	$	278		$	349		$	(71	)

Segment Adjusted EBITDA. For the three months endedMarch 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our Investment in Sunoco Logistics segment decreased due to the following:

• a decrease of $77 million from Sunoco Logistics’ crude oil operations, primarily due to the impact of LIFO inventory accounting on Sunoco Logistics’ contango inventory positions resulting in approximately $60 million of positive earnings during the first quarter 2016, compared to approximately $50 million of negative earnings during the first quarter 2017. The unfavorable LIFO timing is expected to be reversed in future periods as commodity prices fall or the inventory positions are liquidated. Excluding these inventory timing impacts, Adjusted EBITDA for the crude oil increased $33 million compared to the prior year period. This increase related to improved results from Sunoco Logistics’ crude oil pipelines and terminalling activities of $56 million which was largely attributable to expansion capital projects which commenced operations in 2016, the acquisition of Vitol Inc.'s crude oil assets in the fourth quarter 2016, and the formation of Permian Express Partners LLC in the first quarter of 2017. Partially offsetting this improvement was lower operating results from Sunoco Logistics’ crude oil acquisition and marketing activities of $23 million, which includes transportation and storage fees related to Sunoco Logistics’ crude oil pipelines and terminal facilities; and

• a decrease of $2 million from Sunoco Logistics’ refined products operations, primarily due to lower results from Sunoco Logistics’ refined products acquisition and marketing activities of$7 million. This decrease was partially offset by improved results from Sunoco Logistics’ refined products pipelines of$4 millionand improved contributions from joint venture interests of$2 million; offset by

• an increase of $8 million from Sunoco Logistics’ NGLs operations, primarily attributable to increased volumes and fees from Sunoco Logistics’ Mariner NGLs projects of$12 million, which includes Sunoco Logistics’ NGLs pipelines and terminal facilities at Marcus Hook and Nederland. These positive factors were partially offset by lower operating results from Sunoco Logistics’ NGLs acquisition and marketing activities of$2 million.

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All Other

	Three Months Ended March 31,
	2017			2016			Change
Revenues	$	770		$	854		$	(84	)
Cost of products sold	668			761			(93		)
Gross margin	102			93			9
Unrealized (gains) losses on commodity risk management activities	(13		)	3			(16		)
Operating expenses, excluding non-cash compensation expense	(21		)	(21		)	—
Selling, general and administrative expenses, excluding non-cash compensation expense	(21		)	(27		)	6
Adjusted EBITDA related to unconsolidated affiliates	80			61			19
Other	5			24			(19		)
Eliminations	(9		)	(31		)	22
Segment Adjusted EBITDA	$	123		$	102		$	21

Amounts reflected in our all other segment primarily include:

• our equity method investment in limited partnership units of Sunoco LP consisting of43.5 millionunits, representing43.7%of Sunoco LP’s total outstanding common units;

• our natural gas marketing and compression operations;

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

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

For the three months endedMarch 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased primarily due to an increase of $22 million in Adjusted EBITDA related to our investment in PES. The three months endedMarch 31, 2017 also reflected higher gross margin of $9 million and lower selling, general and administrative expenses of $6 million resulting from lower transaction-related expenses. These increases were partially offset by a decrease of $19 million related to the termination of the $75 million annual management fee paid by ETE that ended in 2016.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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

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

Cash Flows

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

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Operating Activities

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

Three months ended March 31,2017 compared to three months ended March 31,2016. Cash provided by operating activities during 2017 was $932 million compared to $960 million for 2016 and net income was $364 million and $376 million for 2017 and 2016, respectively. The difference between net income and cash provided by operating activities for the three months ended March 31,2017 primarily consisted of net changes in operating assets and liabilities of $15 million and non-cash items totaling $509 million.

The non-cash activity in 2017 and 2016 consisted primarily of depreciation, depletion and amortization of $560 million and $470 million, respectively, non-cash compensation expense of $23 million and $19 million, respectively, and equity in earnings of unconsolidated affiliates of $73 million and $76 million, respectively. Non-cash activity in 2017 also included deferred income taxes of $54 million and inventory valuation adjustments of $2 million.

Cash paid for interest, net of interest capitalized, was $377 million and $344 million for the three months ended March 31,2017 and 2016, respectively.

Capitalized interest was $52 million and $57 million for the three months ended March 31,2017 and 2016, respectively.

Investing Activities

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

Three months ended March 31,2017 compared to three months ended March 31,2016. Cash provided by investing activities during 2017 was $280 million compared to $415 million for 2016. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2017 were $1.38 billion compared to $1.81 billion for 2016. Additional detail related to our capital expenditures is provided in the table below. During 2017, we received $2.00 billion in cash related to the Bakken equity sale to MarEn Bakken Company and paid $318 million in cash for all other acquisitions. During 2016, we received $2.20 billion in cash related to the contribution of our Sunoco, Inc. retail business to Sunoco LP.

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The following is a summary of capital expenditures (net of contributions in aid of construction costs) for thethree months ended March 31,2017:

	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
ETP:
Intrastate transportation and storage	$	16	$	5	$	21
Interstate transportation and storage(1)	288		9		297
Midstream	234		16		250
Liquids transportation and services(1)	105		5		110
All other (including eliminations)	47		12		59
Total capital expenditures	690		47		737
Sunoco Logistics:
Crude oil	51		5		56
Natural gas liquids	445		1		446
Refined products	10		7		17
Total capital expenditures	$	1,196	$	60	$	1,256

⁽¹⁾  Includes capital expenditures related to the Bakken, Rover and Bayou Bridge pipeline projects, but excludes amounts related to Sunoco Logistics’ proportionate ownership in the Bakken and Bayou Bridge pipeline projects.

Financing Activities

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

Three months ended March 31,2017 compared to three months ended March 31,2016. Cash used in financing activities during 2017 was $1.28 billion compared to $1.19 billion for 2016. In 2017 and 2016, we received net proceeds from Common Unit offerings of $826 million and $363 million, respectively. In 2016, our subsidiaries received $301 million in net proceeds from the issuance of common units. During 2017, we had a net decrease in our debt level of $1.10 billion compared to a net decrease of $986 million for 2016. We have paid distributions of $896 million to our partners in 2017 compared to $897 million in 2016. We have also paid distributions of $148 million to noncontrolling interests in 2017 compared to $100 million in 2016. In addition, we have received capital contributions of $106 million in cash from noncontrolling interests in 2017 compared to $132 million in 2016. During 2017, we repurchased our outstanding Series A Preferred Units for cash of $53 million and incurred debt issuance costs of $19 million.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	March 31, 2017			December 31, 2016
ETP Senior Notes	$	20,540		$	19,440
Transwestern Senior Notes	657			657
Panhandle Senior Notes	1,085			1,085
Sunoco, Inc. Senior Notes	65			465
Sunoco Logistics Senior Notes	5,350			5,350
Revolving credit facilities and commercial paper:
ETP $3.75 billion Revolving Credit Facility due November 2019(1)	389			2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020(2)	740			1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017(3)	630			630
Bakken Project $2.50 billion Credit Facility due August 2019	2,500			1,100
PennTex $275 million Revolving Credit Facility due December 2019	157			168
Other long-term debt	5			30
Unamortized premiums, net of discounts and fair value adjustments	104			116
Deferred debt issuance costs	(187		)	(180		)
Total debt	32,035			32,930
Less: current maturities of long-term debt	387			1,189
Long-term debt, less current maturities	$	31,648		$	31,741

⁽¹⁾  Includes $389 million and $777 million of commercial paper outstanding at March 31, 2017 and December 31, 2016, respectively.

⁽²⁾  Includes $128 million and $50 million of commercial paper outstanding at March 31, 2017 and December 31, 2016, respectively.

⁽³⁾  Sunoco Logistics’ $1.00 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of March 31, 2017 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis.

ETP as Co-Obligor of Sunoco, Inc. Debt

In connection with previous transactions, ETP became a co-obligor on Sunoco, Inc.’s existing senior notes and debentures. Obligations totaling$400 millionmatured and were repaid in January 2017 and the remaining balance was$65 millionas ofMarch 31, 2017.

ETP Senior Notes

In January 2017, ETP issued$600 millionaggregate principal amount of4.20%senior notes due April 2027 and$900 millionaggregate principal amount of5.30%senior notes due April 2047.ETP used the$1.48 billionnet proceeds from the offering to refinance current maturities and to repay borrowings outstanding under the ETP Credit Facility.

Credit Facilities and Commercial Paper

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to$3.75 billionand matures in November 2019. The indebtedness under the ETP 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, the Partnership initiated a commercial paper program under the borrowing limits established by the$3.75 billionETP Credit Facility.As ofMarch 31, 2017, the ETP Credit Facility had$389 millionof outstanding borrowings, all of which was commercial paper.

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Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a$2.50 billionunsecured revolving credit facility (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to$3.25 billionunder certain conditions.As ofMarch 31, 2017, the Sunoco Logistics Credit Facility had$740 millionof outstanding borrowings, which included$128 millionof commercial paper.

In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility ("364-Day Credit Facility"), due to mature in December 2017, with a total lending capacity of$1.00 billion, including a$630 millionterm loan. The terms of the 364-Day Credit Facility are similar to those of the$2.50 billionSunoco Logistics Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. In connection with Sunoco Logistics’ merger with ETP, the 364-Day Credit Facility is expected to be terminated and repaid in the second quarter of 2017.

Bakken Credit Facility

In August 2016, ETP, Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The$2.50 billioncredit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects. As ofMarch 31, 2017, $2.50 billionwas outstanding under this credit facility.

PennTex Revolving Credit Facility

PennTex maintains a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”) that is expandable up to$400 millionunder certain conditions and matures in December 2019. As ofMarch 31, 2017, PennTex Revolving Credit Facility had$157 millionof outstanding borrowings.

Covenants Related to Our Credit Agreements

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as ofMarch 31, 2017.

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CASH DISTRIBUTIONS

Following the merger of ETP and Sunoco Logistics in April 2017, we no longer have outstanding common units; therefore, we no longer declare quarterly distributions. The partnership agreement of Post-Merger ETP includes distribution provisions similar to those of ETP prior to the merger.

For the quarter endedDecember 31, 2016, ETP and Sunoco Logistics paid distributions onFebruary 14, 2017of$1.0550and$0.52, respectively, per common unit. For the quarter endedMarch 31, 2017, Post-Merger ETP declared a distribution of$0.5350per common unit, payable onMay 15, 2017to unitholders of record onMay 10, 2017.

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

	Three Months Ended March 31,
	2017			2016
	Post-Merger ETP			ETP			Sunoco Logistics
Limited Partners:
Common Units held by public	$	567		$	526		$	107
Common Units held by ETP	—			—			33
Common Units held by ETE	15			3			—
Class H Units held by ETE	—			83			—
General Partner interest	4			8			3
Incentive distributions held by ETE	377			331			89
IDR relinquishments net of Class I Unit distributions	(157		)	(34		)	—
Total distributions declared to partners	$	806		$	917		$	232

PennTex Quarterly Distributions of Available Cash

PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of$0.2750per unit at the end of each quarter. Following are distributions declared and/or paid by PennTex subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 14, 2017	$	0.2950
March 31, 2017	May 5, 2017	May 12, 2017	0.2950

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

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	March 31, 2017							December 31, 2016
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	80,000		$	—		$	—	(682,500	)	$	—		$	—
Basis Swaps IFERC/NYMEX(1)	8,372,500		—			—		2,242,500		(1		)	—
Power (Megawatt):
Forwards	225,480		(1		)	—		391,880		(1		)	1
Futures	(58,000	)	—			—		109,564		—			—
Options – Puts	67,200		—			—		(50,400	)	—			—
Options – Calls	447,200		1			—		186,400		1			—
Crude (Bbls) – Futures	(1,418,000	)	3			9		(617,000	)	(4		)	6
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(5,247,500	)	(3		)	2		10,750,000		2			—
Swing Swaps IFERC	(12,185,000	)	(1		)	1		(5,662,500	)	(1		)	1
Fixed Swaps/Futures	(51,102,500	)	(9		)	17		(52,652,500	)	(27		)	19
Forward Physical Contracts	16,763,209		4			—		(22,492,489	)	1			8
Natural Gas Liquid (Bbls) – Forwards/Swaps	(1,827,400	)	3			12		(5,786,627	)	(40		)	35
Refined Products (Bbls) – Futures	(1,217,000	)	(3		)	8		(2,240,000	)	(16		)	17
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(13,877,500	)	—			—		(36,370,000	)	2			1
Fixed Swaps/Futures	(13,877,500	)	(3		)	5		(36,370,000	)	(26		)	14

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

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

Interest Rate Risk

As of March 31, 2017, we had $1.89 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $19 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

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

Term	Type(1)	Notional Amount Outstanding
		March 31, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	500	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

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

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

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $200 million as of March 31, 2017. For the $1.50 billion of interest rate swaps whereby we pay a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $32 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Under the supervision and with the participation of senior management, including the Chief Executive Officer (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of March 31, 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 endedMarch 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 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 March 31, 2017.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in our Annual Report on Form 10-K for our previous fiscal year ended December 31, 2016.

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ITEM 6. EXHIBITS

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

Exhibit Number	Description
4.1	Sixteenth Supplemental Indenture dated as of January 17, 2017 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed January 17, 2017).
10.1	Third Amendment to Second Amended and Restated Credit Agreement by and among Energy Transfer Partners, L.P., the Lenders party thereto and Wells Fargo Bank, National Association, in its capacity as administrative agent for the Lenders dated as of March 29, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed April 4, 2017).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.
**	Furnished herewith.

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SIGNATURE

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

		ENERGY TRANSFER, LP
		By:	SXL Acquisition Sub LLC,
			its General Partner
Date:	May 4, 2017	By:	/s/ A. Troy Sturrock
			A. Troy Sturrock
			Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)

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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: May 4, 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: May 4, 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 March 31, 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: May 4, 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 March 31, 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: May 4, 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 - shares	3 Months Ended
	Mar. 31, 2017	Apr. 28, 2017
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	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 291	$ 360
Accounts receivable, net	3,025	3,002
Accounts receivable from related companies	289	209
Inventories	1,546	1,712
Derivative assets	7	20
Other current assets	347	426
Total current assets	5,505	5,729
Property, plant and equipment	60,292	58,220
Accumulated depreciation and depletion	(7,760)	(7,303)
Property, plant and equipment, net	52,532	50,917
Advances to and investments in unconsolidated affiliates	4,294	4,280
Other non-current assets, net	685	672
Intangible assets, net	5,506	4,696
Goodwill	3,915	3,897
Total assets	72,437	70,191
Current liabilities:
Accounts payable	2,936	2,900
Accounts payable to related companies	188	43
Derivative liabilities	124	166
Accrued and other current liabilities	1,841	1,905
Current maturities of long-term debt	387	1,189
Total current liabilities	5,476	6,203
Long-term debt, less current maturities	31,648	31,741
Long-term notes payable – related company	0	250
Non-current derivative liabilities	72	76
Deferred income taxes	4,432	4,394
Other non-current liabilities	1,053	952
Commitments and contingencies
Series A Preferred Units	0	33
Redeemable noncontrolling interests	15	15
Equity:
General Partner	193	206
Limited Partners:
Common Unitholders	16,422	14,946
Class H Unitholder	3,483	3,480
Class I Unitholder	0	2
Accumulated other comprehensive income	8	8
Total partners’ capital	20,106	18,642
Noncontrolling interest	9,635	7,885
Total equity	29,741	26,527
Total liabilities and equity	$ 72,437	$ 70,191

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Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
REVENUES:
Natural gas sales	$ 1,012	$ 838
NGL sales	1,547	940
Crude sales	2,347	1,210
Gathering, transportation and other fees	1,024	960
Refined product sales	471	245
Other	494	288
Total revenues	6,895	4,481
COSTS AND EXPENSES:
Cost of products sold	5,192	2,968
Operating expenses	379	348
Depreciation, depletion and amortization	560	470
Selling, general and administrative	110	81
Total costs and expenses	6,241	3,867
OPERATING INCOME	654	614
OTHER INCOME (EXPENSE):
Interest expense, net	(339)	(319)
Equity in earnings of unconsolidated affiliates	73	76
Gains (losses) on interest rate derivatives	5	(70)
Other, net	26	17
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	419	318
Income tax expense (benefit)	55	(58)
NET INCOME	364	376
Less: Net income attributable to noncontrolling interest	40	65
NET INCOME ATTRIBUTABLE TO PARTNERS	324	311
General Partner’s interest in net income	206	297
Class H Unitholder’s interest in net income	98	79
Class I Unitholder’s interest in net income	0	2
Common Unitholders’ interest in net income (loss)	$ 20	$ (67)
NET INCOME (LOSS) PER COMMON UNIT:
Basic	$ 0.02	$ (0.15)
Diluted	$ 0.02	$ (0.15)

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Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 364	$ 376
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2	2
Actuarial loss relating to pension and other postretirement benefit plans	(2)	(9)
Foreign currency translation adjustments	0	(1)
Change in other comprehensive income from unconsolidated affiliates	0	(6)
Total other comprehensive income (loss)	0	(14)
Comprehensive income	364	362
Less: Comprehensive income attributable to noncontrolling interest	40	65
Comprehensive income attributable to partners	$ 324	$ 297

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Consolidated Statement Of Equity - 3 months ended Mar. 31, 2017 - USD ($) $ in Millions	Total	General Partner	Common Units	Class H Units	Class I Units	Accumulated Other Comprehensive Income	Noncontrolling Interest
Balance, December 31, 2016 at Dec. 31, 2016	$ 26,527	$ 206	$ 14,946	$ 3,480	$ 2	$ 8	$ 7,885
Distributions to partners	896	219	580	95	2	0	0
Distributions to noncontrolling interest	(148)	0	0	0	0	0	(148)
Units issued for cash	826	0	826	0	0	0	0
Capital contributions from noncontrolling interest	1,094	0	0	0	0	0	1,094
Sale of Bakken Pipeline interest	2,000	0	1,260	0	0	0	740
Other, net	(26)	0	(50)	0	0	0	24
Net income	364	206	20	98	0	0	40
Balance, March 31, 2017 at Mar. 31, 2017	$ 29,741	$ 193	$ 16,422	$ 3,483	$ 0	$ 8	$ 9,635

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Consolidated Statements Of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OPERATING ACTIVITIES
Net income	$ 364	$ 376
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	560	470
Deferred income taxes	54	(57)
Amortization included in interest expense	1	7
Inventory valuation adjustments	(2)	26
Unit-based compensation expense	23	19
Distributions on unvested awards	(8)	(7)
Equity in earnings of unconsolidated affiliates	(73)	(76)
Distributions from unconsolidated affiliates	82	84
Other non-cash	(52)	(12)
Net change in operating assets and liabilities, net of effects of acquisition	(15)	144
Net cash provided by operating activities	932	960
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
Cash paid for all other acquisitions	318	0
Capital expenditures, excluding allowance for equity funds used during construction	(1,384)	(1,819)
Contributions in aid of construction costs	6	10
Contributions to unconsolidated affiliates	(111)	(31)
Distributions from unconsolidated affiliates in excess of cumulative earnings	90	51
Proceeds from the sale of assets	0	8
Change in restricted cash	0	(1)
Other	(3)	(3)
Net cash provided by investing activities	280	415
FINANCING ACTIVITIES
Proceeds from borrowings	6,366	2,938
Repayments of long-term debt	(7,216)	(3,914)
Repayments of Related Party Debt	250	10
Units issued for cash	826	363
Subsidiary units issued for cash	0	301
Capital contributions from noncontrolling interest	106	132
Distributions to partners	(896)	(897)
Distributions to noncontrolling interest	(148)	(100)
Payments for Repurchase of Preferred Stock and Preference Stock	(53)	0
Debt issuance costs	19	0
Proceeds from (Payments for) Other Financing Activities	3	0
Net cash used in financing activities	(1,281)	(1,187)
Increase (decrease) in cash and cash equivalents	(69)	188
Cash and cash equivalents, beginning of period	360	527
Cash and cash equivalents, end of period	$ 291	$ 715

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Operations And Organization

3 Months Ended

Mar. 31, 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 “ETP.”

In April 2017, ETP merged with a subsidiary of Sunoco Logistics Partners L.P., at which time ETP 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.” Additional information related to the merger is included in Note 2 below. For purposes of maintaining clarity, the following references are used herein:

• References to “ETP” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the merger and 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 “Post-Merger 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, a Texas limited partnership and Regency, a Delaware limited partnership, 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 is 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, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:

• Transwestern, a Delaware limited liability company 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, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.

• ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.

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

• ETC MEP, a Delaware limited liability company that directly owns a 50% interest in MEP.

• ET Rover, a Delaware limited liability company.

• ETC Compression, LLC, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

• ETP Holdco, a Delaware limited liability company that 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.

• Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.

• PennTex, a publicly traded Delaware limited partnership that provides natural gas gathering and processing and residue gas and natural gas liquids transportation services to producers.

• Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP LLC, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETE transferred to ETP 21 million ETP common units. These operations were reported within the retail marketing segment. In connection with this transaction, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. Additionally, in March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business effective January 1, 2016.

Our financial statements reflect the following reportable business segments:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•liquids transportation and services;

•investment in Sunoco Logistics; 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 the Partnership’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. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

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Acquisitions and Contribution Transactions

3 Months Ended

Mar. 31, 2017

CONTRIBUTION TRANSACTION [Abstract]

Contribution Transaction

CONTRIBUTION TRANSACTIONS

ETP and Sunoco Logistics Merger

In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction.Under the terms of the transaction, ETP unitholders received1.5common units of Sunoco Logistics for each common unit of ETP they owned.Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.Based on the ETP units outstanding at the closing of the merger, Sunoco Logistics issued approximately845 millionSunoco Logistics common units to ETP unitholders. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP 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 ETP 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 ETP at the effective time of the merger were cancelled.

Sunoco Logistics’ Permian Express Partners

In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately85%. Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of Sunoco Logistics and accordingly is reflected as a consolidated subsidiary of the Partnership. ExxonMobil Corp.’s interest is reflected as noncontrolling interest in the consolidated balance sheets. Sunoco Logistics' intangible assets increased by $547 million attributable to customer relationships that were recorded in connection with the formation of PEP.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a60%membership interest and Sunoco Logistics 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. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25%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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Cash And Cash Equivalents

3 Months Ended

Mar. 31, 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:

	Three Months Ended March 31,
	2017			2016
Accounts receivable	$	(23	)	$	(9	)
Accounts receivable from related companies	(44		)	90
Inventories	168			(11		)
Other current assets	43			(99		)
Other non-current assets, net	(18		)	11
Accounts payable	(88		)	51
Accounts payable to related companies	120			(2		)
Accrued and other current liabilities	(139		)	4
Other non-current liabilities	(2		)	21
Derivative assets and liabilities, net	(32		)	88
Net change in operating assets and liabilities, net of effects of acquisition	$	(15	)	$	144

Non-cash investing and financing activities are as follows:

	Three Months Ended March 31,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	832	$	826
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	—		5
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—

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Inventories

3 Months Ended

Mar. 31, 2017

Inventory, Gross [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:

	March 31, 2017		December 31, 2016
Natural gas and NGLs	$	474	$	699
Crude oil	784		683
Refined products	86		113
Spare parts and other	202		217
Total inventories	$	1,546	$	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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Fair Value Measurements

3 Months Ended

Mar. 31, 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 March 31, 2017 was $33.09 billion and $32.04 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, interest rate derivatives and embedded derivatives in the Preferred Units 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. Derivatives related to the embedded derivatives in our preferred units at December 31, 2016 were valued using a binomial lattice model. The market inputs utilized in the model included credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the three months endedMarch 31, 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 March 31, 2017 and December 31, 2016 based on inputs used to derive their fair values:

				Fair Value Measurements at March 31, 2017
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	7		$	7		$	—		$	—
Fixed Swaps/Futures	30			30			—			—
Forward Physical Swaps	4			—			4			—
Power:
Futures	7			—			7			—
Options – Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	91			91			—			—
Crude – Futures	12			12			—			—
Total commodity derivatives	152			141			11			—
Total assets	$	152		$	141		$	11		$	—
Liabilities:
Interest rate derivatives	$	(188	)	$	—		$	(188	)	$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(10		)	(10		)	—			—
Swing Swaps IFERC	(1		)	—			(1		)	—
Fixed Swaps/Futures	(42		)	(42		)	—			—
Power:
Forwards	(8		)	—			(8		)	—
Natural Gas Liquids – Forwards/Swaps	(88		)	(88		)	—			—
Refined Products – Futures	(3		)	(3		)	—			—
Crude – Futures	(9		)	(9		)	—			—
Total commodity derivatives	(161		)	(152		)	(9		)	—
Total liabilities	$	(349	)	$	(152	)	$	(197	)	$	—

				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 the ETP 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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Net Income Per Limited Partner Unit

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Net Income (Loss) Per Limited Partner Unit [Text Block]

NET INCOME (LOSS) PER LIMITED PARTNER UNIT

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

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

	Three Months Ended March 31,
	2017			2016
Net income	$	364		$	376
Less: Income attributable to noncontrolling interest	40			65
Net income, net of noncontrolling interest	324			311
General Partner’s interest in net income	206			297
Class H Unitholder’s interest in net income	98			79
Class I Unitholder’s interest in net income	—			2
Common Unitholders’ interest in net income (loss)	20			(67		)
Additional earnings allocated to General Partner	(3		)	(3		)
Distributions on employee unit awards, net of allocation to General Partner	(7		)	(5		)
Net income (loss) available to Common Unitholders	$	10		$	(75	)
Weighted average Common Units – basic (1)	548.2			490.2
Basic net income (loss) per Common Unit	$	0.02		$	(0.15	)
Diluted net income (loss) available to Common Unitholders	$	10		$	(75	)
Weighted average Common Units – basic (1)	548.2			490.2
Dilutive effect of unvested employee unit awards	1.4			—
Weighted average Common Units – diluted (1)	549.6			490.2
Diluted net income (loss) per Common Unit	$	0.02		$	(0.15	)

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

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

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Debt Obligations

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Debt Obligations

DEBT OBLIGATIONS

ETP as Co-Obligor of Sunoco, Inc. Debt

In connection with previous transactions, ETP became a co-obligor on Sunoco, Inc.’s existing senior notes and debentures. Obligations totaling$400 millionmatured and were repaid in January 2017 and the remaining balance was$65 millionas ofMarch 31, 2017.

ETP Senior Notes

In January 2017, ETP issued$600 millionaggregate principal amount of4.20%senior notes due April 2027 and$900 millionaggregate principal amount of5.30%senior notes due April 2047.ETP used the$1.48 billionnet proceeds from the offering to refinance current maturities and to repay borrowings outstanding under the ETP Credit Facility.

Credit Facilities and Commercial Paper

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to$3.75 billionand matures in November 2019. The indebtedness under the ETP 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, the Partnership initiated a commercial paper program under the borrowing limits established by the$3.75 billionETP Credit Facility.As ofMarch 31, 2017, the ETP Credit Facility had$389 millionof outstanding borrowings, all of which was commercial paper.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a$2.50 billionunsecured revolving credit facility (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to$3.25 billionunder certain conditions.As ofMarch 31, 2017, the Sunoco Logistics Credit Facility had$740 millionof outstanding borrowings, which included$128 millionof commercial paper.

In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility ("364-Day Credit Facility"), due to mature in December 2017, with a total lending capacity of$1.00 billion, including a$630 millionterm loan. The terms of the 364-Day Credit Facility are similar to those of the$2.50 billionSunoco Logistics Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. In connection with Sunoco Logistics’ merger with ETP, the 364-Day Credit Facility is expected to be terminated and repaid in the second quarter of 2017.

Bakken Credit Facility

In August 2016, ETP, Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The$2.50 billioncredit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects. As ofMarch 31, 2017, $2.50 billionwas outstanding under this credit facility.

PennTex Revolving Credit Facility

PennTex maintains a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”) that is expandable up to$400 millionunder certain conditions and matures in December 2019. As ofMarch 31, 2017, PennTex Revolving Credit Facility had$157 millionof outstanding borrowings.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as ofMarch 31, 2017.

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Series A Preferred Units (Notes)

3 Months Ended

Mar. 31, 2017

Series A Preferred Units [Abstract]

Preferred Units [Text Block]

SERIES A PREFERRED UNITS

In January 2017, ETP repurchased all of its1.9 millionoutstanding Series A Preferred Units for cash in the aggregate amount of$53 million.

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Equity

3 Months Ended

Mar. 31, 2017

Partners' Capital Notes [Abstract]

Equity

EQUITY

ETP

The changes in outstanding common units during the three months ended March 31,2017 were as follows:

	Number of Units
Number of common units at December 31, 2016	529.9
Common units issued in connection with equity distribution agreements	5.4
Common units issued in connection with the distribution reinvestment plan	1.9
Common units issued to ETE in a private placement transaction	15.8
Number of common units at March 31, 2017	553.0

During the three months ended March 31,2017, the Partnership received proceeds of $194 million, net of $2 million commissions, from the issuance of common units pursuant to an equity distribution agreement, which were used for general partnership purposes. In connection with the merger of ETP and Sunoco Logistics in April 2017, the equity distribution agreement was terminated.

During the three months ended March 31,2017, distributions of $71 million were reinvested under the distribution reinvestment plan. In connection with the merger of ETP and Sunoco Logistics in April 2017, the distribution reinvestment plan was terminated.

Sunoco Logistics

There was no activity under the Sunoco Logistics equity distribution agreement for the three months endedMarch 31, 2017.

January 2017 Private Placement

In January 2017, the Partnership sold15.8 millionETP Common Units to ETE in a private placement transaction for gross proceeds of approximately$568 million.

Bakken Equity Sale

As discussed in Note 2, in February 2017, Bakken Holdings Company LLC sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, for $2.00 billion in cash. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. As a result of the sale, ETP recorded a deemed contribution of $1.26 billion during the three months ended March 31, 2017, representing the difference between proceeds from the sale and the proportionate share of the book value of the subsidiary, which was allocated to noncontrolling interest.

Quarterly Distributions of Available Cash

Following the merger of ETP and Sunoco Logistics in April 2017, we no longer have outstanding common units; therefore, we no longer declare quarterly distributions. The partnership agreement of Post-Merger ETP includes distribution provisions similar to those of ETP prior to the merger.

For the quarter endedDecember 31, 2016, ETP and Sunoco Logistics paid distributions onFebruary 14, 2017of$1.0550and$0.52, respectively, per common unit. For the quarter endedMarch 31, 2017, Post-Merger ETP declared a distribution of$0.5350per common unit, payable onMay 15, 2017to unitholders of record onMay 10, 2017.

PennTex Quarterly Distributions of Available Cash

PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of$0.2750per unit at the end of each quarter. Following are distributions declared and/or paid by PennTex subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 14, 2017	$	0.2950
March 31, 2017	May 5, 2017	May 12, 2017	0.2950

Accumulated Other Comprehensive Income

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

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

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

3 Months Ended

Mar. 31, 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, ETP agreed to provide contingent residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchases. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its 7.00% senior notes, which reduced the remaining amount supported by ETP to $102 million. In March 2017, AmeriGas issued a notice of redemption for the remaining outstanding 7.00% senior notes, which senior notes will be redeemed in May 2017.

Guarantee of Sunoco LP Notes

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

NGL Pipeline Regulation

We have interests in NGL pipelines located in Texas and New Mexico. We commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

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 through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended March 31,
	2017		2016
Rental expense	$	20	$	18

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 gathering near a construction site on the Dakota Access pipeline project in North Dakota to protest the development of the pipeline project. Some of the protesters eventually 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 have moved to dismiss the lawsuit and Dakota Access has responded. The court’s decision is still pending.

In the meantime, 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. As explained below, 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 challenging the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claiming 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 moved to intervene in the case and that motion was granted by the Court. 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 Department of Justice, and the Department of the Interior released a joint statement stating 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 District Court. The U.S. District Court denied the emergency motion for an injunction pending the appeal. 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 statues 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 construction. 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. The CRST appealed and requested an injunction pending appeal in both the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. CRST has filed a motion with the D.C. Circuit for the purpose of voluntarily seeking dismissal of its appeal of its claims related to religious rights.

The SRST and the CRST have sought leave to amend their complaints to incorporate their religious freedom and other claims and have moved for summary judgment on their claims against the government based on treaty rights and the National Environmental Policy Act. Dakota Access has also moved for summary judgment with respect to these claims. The district court is still considering these motions. Briefing is ongoing.

In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits in an effort to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST.

Construction of the pipeline is now complete. 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.

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 included are governmental authorities. The plaintiffs primarily assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As ofMarch 31, 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. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. All parties agreed to participate in global settlement discussions in a global mediation forum before Hon. Garrett Brown (Ret.), a Judicial Arbitration Mediation Service mediator. The remaining portion of the New Jersey case remains in the multidistrict litigation. Sunoco, Inc. and Sunoco, Inc. (R&M) participated in mediation with Judge Brown on November 2 through November 3, 2016 and on November 30, 2016. 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. Management believes that 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 does not believe that any such adverse determination would 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 Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal. 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. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ filed their Answering Brief on July 29, 2016. On August 31, 2016, Dieckman filed his Reply Brief. Oral argument was held on November 16, 2016 before the Delaware Supreme Court. 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.

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

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise has filed a notice of appeal with the Texas Court of Appeals, and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. The Court of Appeals is taking the briefs under advisement. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.

Sunoco Logistics Merger Litigation

Between January 6, 2017 and February 8, 2017, seven purported ETP common unitholders (“Plaintiffs”) separately filed seven putative unitholder class action lawsuits challenging the merger and the disclosures made in connection with the merger. Since then, two of the Plaintiffs have non-suited their claims. The lawsuits remaining 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”). The Duany Lawsuit and Epstein Lawsuit are filed against ETP, ETP GP, ETP GP, LLC, ETE, and the members of the ETP Board. The Shure Lawsuit and Verlin Lawsuit are filed against ETP, ETP GP, the members of the ETP Board, ETE, Sunoco Logistics, and Sunoco Logistics GP. The Sgnilek Lawsuit is filed against ETP, ETP GP, ETP GP LLC, ETE, the members of the ETP Board, Sunoco Logistics and Sunoco Logistics GP (collectively “Defendants”).

Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. According to Plaintiffs, the preliminary joint proxy statement/prospectus is allegedly misleading because, among other things, it fails to disclose certain information concerning, in general, (a) the background and process that led to the merger; (b) ETE’s, ETP’s, and Sunoco Logistics’ financial projections; (c) the financial analysis and fairness opinion provided by Barclays; and (d) alleged conflicts of interest concerning Barclays, ETE, and certain officers and directors of ETP and ETE. Based on these allegations, and in general, 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 GP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Logistics GP 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.

Defendants’ dates to answer, move to dismiss, or otherwise respond to the Lawsuits have not yet been set. Defendants cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this quarterly report, nor can Defendants predict the amount of time and expense that will be required to resolve such litigation. 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 of March 31, 2017 and December 31, 2016, accruals of approximately $94 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

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

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

Environmental Matters

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

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.

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.

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

• Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of March 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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

	March 31, 2017		December 31, 2016
Current	$	28	$	26
Non-current	288		283
Total environmental liabilities	$	316	$	309

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

During the three months ended March 31,2017 and 2016, Sunoco, Inc. recorded $2 million and $6 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 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

In September 2016, EPA issued an NOV related to well monitoring procedures at Sunoco Logistics’ Inkster terminal located near Detroit, Michigan. Penalties of approximately $0.1 million were assessed in connection with the NOV, which Sunoco Logistics paid in March 2017, to close out this matter. 

In December 2016, Sunoco Logistics received multiple NOVs from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016.  Sunoco Logistics also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC.  These actions propose penalties in excess of $0.1 million, and Sunoco Logistics is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows, or financial position.

Our operations are also subject to the requirements of the 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

3 Months Ended

Mar. 31, 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.

Sunoco Logistics utilizes 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:

	March 31, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	80,000		2017	(682,500	)	2017
Basis Swaps IFERC/NYMEX(1)	8,372,500		2017	2,242,500		2017
Power (Megawatt):
Forwards	225,480		2017-2018	391,880		2017-2018
Futures	(58,000	)	2017-2018	109,564		2017-2018
Options – Puts	67,200		2017	(50,400	)	2017
Options – Calls	447,200		2017	186,400		2017
Crude (Bbls) – Futures	(1,418,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(5,247,500	)	2017-2018	10,750,000		2017-2018
Swing Swaps IFERC	(12,185,000	)	2017	(5,662,500	)	2017
Fixed Swaps/Futures	(51,102,500	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	16,763,209		2017	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(1,827,400	)	2017	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(1,217,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(13,877,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(13,877,500	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	13,877,500		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
		March 31, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	500	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200
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
	March 31, 2017		December 31, 2016		March 31, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	—	$	(2	)	$	(4	)
	—		—		(2		)	(4		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	139		338		(145		)	(416		)
Commodity derivatives	13		24		(14		)	(52		)
Interest rate derivatives	—		—		(188		)	(193		)
Embedded derivatives in ETP Preferred Units	—		—		—			(1		)
	152		362		(347		)	(662		)
Total derivatives	$	152	$	362	$	(349	)	$	(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	March 31, 2017			December 31, 2016			March 31, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(188	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	13			24			(14		)	(52		)
Broker cleared derivative contracts	Other current assets	139			338			(147		)	(420		)
Total gross derivatives		152			362			(349		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(6		)	(4		)	6			4
Payments on margin deposit	Other current assets	(133		)	(338		)	133			338
Total net derivatives		$	13		$	20		$	(210	)	$	(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 March 31,
		2017			2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(4	)	$	(4	)
Total		$	(4	)	$	(4	)

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	11		$	(9	)
Commodity derivatives – Non-trading	Cost of products sold	(10		)	5
Interest rate derivatives	Gains (losses) on interest rate derivatives	5			(70		)
Embedded derivatives	Other, net	1			—
Total		$	7		$	(74	)

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Related Party Transactions

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

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 have subsequently expired.

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 March 31,
	2017		2016
Affiliated revenues	$	118	$	74

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

	March 31, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	3	$	22
Sunoco LP	200		96
PES	8		6
FGT	17		15
Lake Charles LNG	3		4
Trans-Pecos Pipeline, LLC	1		1
Comanche Trail Pipeline, LLC	1		—
Other	56		65
Total accounts receivable from related companies:	$	289	$	209
Accounts payable to related companies:
Sunoco LP	$	168	$	20
FGT	—		1
Lake Charles LNG	3		3
Other	17		19
Total accounts payable to related companies:	$	188	$	43

	March 31, 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

3 Months Ended

Mar. 31, 2017

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

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

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•liquids transportation and services;

•investment in Sunoco Logistics; and

•all other.

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 ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of March 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.7% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented.

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

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our liquids transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in Sunoco Logistics 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 March 31,
	2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	768		$	446
Intersegment revenues	48			112
	816			558
Interstate transportation and storage:
Revenues from external customers	231			254
Intersegment revenues	4			5
	235			259
Midstream:
Revenues from external customers	565			527
Intersegment revenues	1,072			565
	1,637			1,092
Liquids transportation and services:
Revenues from external customers	1,508			829
Intersegment revenues	114			90
	1,622			919
Investment in Sunoco Logistics:
Revenues from external customers	3,185			1,729
Intersegment revenues	34			48
	3,219			1,777
All other:
Revenues from external customers	638			696
Intersegment revenues	132			158
	770			854
Eliminations	(1,404		)	(978		)
Total revenues	$	6,895		$	4,481

	Three Months Ended March 31,
	2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	169		$	179
Interstate transportation and storage	265			292
Midstream	320			263
Liquids transportation and services	259			227
Investment in Sunoco Logistics	278			349
All other	123			102
Total	1,414			1,412
Depreciation, depletion and amortization	(560		)	(470		)
Interest expense, net	(339		)	(319		)
Gains (losses) on interest rate derivatives	5			(70		)
Non-cash unit-based compensation expense	(23		)	(19		)
Unrealized gains (losses) on commodity risk management activities	64			(63		)
Inventory valuation adjustments	2			(26		)
Adjusted EBITDA related to unconsolidated affiliates	(239		)	(219		)
Equity in earnings of unconsolidated affiliates	73			76
Other, net	22			16
Income before income tax expense (benefit)	$	419		$	318

	March 31, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	4,801	$	5,164
Interstate transportation and storage	10,066		10,833
Midstream	18,366		18,011
Liquids transportation and services	12,672		11,296
Investment in Sunoco Logistics	19,425		18,819
All other	7,107		6,068
Total assets	$	72,437	$	70,191

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Operations And Organization Accounting Policy (Policies)

3 Months Ended

Mar. 31, 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. We expect that our adoption of this standard will change our approach for testing goodwill for impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

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Cash And Cash Equivalents (Tables)

3 Months Ended

Mar. 31, 2017

Cash and Cash Equivalents [Abstract]

Net Cash Provided By Operating Activities

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:

	Three Months Ended March 31,
	2017			2016
Accounts receivable	$	(23	)	$	(9	)
Accounts receivable from related companies	(44		)	90
Inventories	168			(11		)
Other current assets	43			(99		)
Other non-current assets, net	(18		)	11
Accounts payable	(88		)	51
Accounts payable to related companies	120			(2		)
Accrued and other current liabilities	(139		)	4
Other non-current liabilities	(2		)	21
Derivative assets and liabilities, net	(32		)	88
Net change in operating assets and liabilities, net of effects of acquisition	$	(15	)	$	144

Non-Cash Investing And Financing Activities

Non-cash investing and financing activities are as follows:

	Three Months Ended March 31,
	2017		2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	832	$	826
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	—		5
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988	$	—

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Inventories (Tables)

3 Months Ended

Mar. 31, 2017

Inventory, Gross [Abstract]

Schedule Of Inventories

Inventories consisted of the following:

	March 31, 2017		December 31, 2016
Natural gas and NGLs	$	474	$	699
Crude oil	784		683
Refined products	86		113
Spare parts and other	202		217
Total inventories	$	1,546	$	1,712

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2017 and December 31, 2016 based on inputs used to derive their fair values:

				Fair Value Measurements at March 31, 2017
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	7		$	7		$	—		$	—
Fixed Swaps/Futures	30			30			—			—
Forward Physical Swaps	4			—			4			—
Power:
Futures	7			—			7			—
Options – Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	91			91			—			—
Crude – Futures	12			12			—			—
Total commodity derivatives	152			141			11			—
Total assets	$	152		$	141		$	11		$	—
Liabilities:
Interest rate derivatives	$	(188	)	$	—		$	(188	)	$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(10		)	(10		)	—			—
Swing Swaps IFERC	(1		)	—			(1		)	—
Fixed Swaps/Futures	(42		)	(42		)	—			—
Power:
Forwards	(8		)	—			(8		)	—
Natural Gas Liquids – Forwards/Swaps	(88		)	(88		)	—			—
Refined Products – Futures	(3		)	(3		)	—			—
Crude – Futures	(9		)	(9		)	—			—
Total commodity derivatives	(161		)	(152		)	(9		)	—
Total liabilities	$	(349	)	$	(152	)	$	(197	)	$	—

				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 the ETP 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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Net Income Per Limited Partner Unit (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

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

	Three Months Ended March 31,
	2017			2016
Net income	$	364		$	376
Less: Income attributable to noncontrolling interest	40			65
Net income, net of noncontrolling interest	324			311
General Partner’s interest in net income	206			297
Class H Unitholder’s interest in net income	98			79
Class I Unitholder’s interest in net income	—			2
Common Unitholders’ interest in net income (loss)	20			(67		)
Additional earnings allocated to General Partner	(3		)	(3		)
Distributions on employee unit awards, net of allocation to General Partner	(7		)	(5		)
Net income (loss) available to Common Unitholders	$	10		$	(75	)
Weighted average Common Units – basic (1)	548.2			490.2
Basic net income (loss) per Common Unit	$	0.02		$	(0.15	)
Diluted net income (loss) available to Common Unitholders	$	10		$	(75	)
Weighted average Common Units – basic (1)	548.2			490.2
Dilutive effect of unvested employee unit awards	1.4			—
Weighted average Common Units – diluted (1)	549.6			490.2
Diluted net income (loss) per Common Unit	$	0.02		$	(0.15	)

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

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

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Equity (Tables)

3 Months Ended

Mar. 31, 2017

Change In Common Units

The changes in outstanding common units during the three months ended March 31,2017 were as follows:

	Number of Units
Number of common units at December 31, 2016	529.9
Common units issued in connection with equity distribution agreements	5.4
Common units issued in connection with the distribution reinvestment plan	1.9
Common units issued to ETE in a private placement transaction	15.8
Number of common units at March 31, 2017	553.0

Accumulated Other Comprehensive Income

Accumulated Other Comprehensive Income

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

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

PennTex [Member]

Distributions Made to Limited Partner, by Distribution [Table Text Block]

PennTex Quarterly Distributions of Available Cash

PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of$0.2750per unit at the end of each quarter. Following are distributions declared and/or paid by PennTex subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 14, 2017	$	0.2950
March 31, 2017	May 5, 2017	May 12, 2017	0.2950

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

3 Months Ended

Mar. 31, 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 through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended March 31,
	2017		2016
Rental expense	$	20	$	18

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.

	March 31, 2017		December 31, 2016
Current	$	28	$	26
Non-current	288		283
Total environmental liabilities	$	316	$	309

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Derivative Assets And Liabilities (Tables)

3 Months Ended

Mar. 31, 2017

Derivative [Line Items]

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:

	March 31, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	80,000		2017	(682,500	)	2017
Basis Swaps IFERC/NYMEX(1)	8,372,500		2017	2,242,500		2017
Power (Megawatt):
Forwards	225,480		2017-2018	391,880		2017-2018
Futures	(58,000	)	2017-2018	109,564		2017-2018
Options – Puts	67,200		2017	(50,400	)	2017
Options – Calls	447,200		2017	186,400		2017
Crude (Bbls) – Futures	(1,418,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(5,247,500	)	2017-2018	10,750,000		2017-2018
Swing Swaps IFERC	(12,185,000	)	2017	(5,662,500	)	2017
Fixed Swaps/Futures	(51,102,500	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	16,763,209		2017	(22,492,489	)	2017
Natural Gas Liquid (Bbls) – Forwards/Swaps	(1,827,400	)	2017	(5,786,627	)	2017
Refined Products (Bbls) – Futures	(1,217,000	)	2017	(2,240,000	)	2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(13,877,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(13,877,500	)	2017	(36,370,000	)	2017
Hedged Item – Inventory	13,877,500		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
		March 31, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	500	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200
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
	March 31, 2017		December 31, 2016		March 31, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	—	$	(2	)	$	(4	)
	—		—		(2		)	(4		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	139		338		(145		)	(416		)
Commodity derivatives	13		24		(14		)	(52		)
Interest rate derivatives	—		—		(188		)	(193		)
Embedded derivatives in ETP Preferred Units	—		—		—			(1		)
	152		362		(347		)	(662		)
Total derivatives	$	152	$	362	$	(349	)	$	(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	March 31, 2017			December 31, 2016			March 31, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(188	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	13			24			(14		)	(52		)
Broker cleared derivative contracts	Other current assets	139			338			(147		)	(420		)
Total gross derivatives		152			362			(349		)	(666		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(6		)	(4		)	6			4
Payments on margin deposit	Other current assets	(133		)	(338		)	133			338
Total net derivatives		$	13		$	20		$	(210	)	$	(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 March 31,
		2017			2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(4	)	$	(4	)
Total		$	(4	)	$	(4	)

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 March 31,
		2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	11		$	(9	)
Commodity derivatives – Non-trading	Cost of products sold	(10		)	5
Interest rate derivatives	Gains (losses) on interest rate derivatives	5			(70		)
Embedded derivatives	Other, net	1			—
Total		$	7		$	(74	)

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2017		2016
Affiliated revenues	$	118	$	74

Related Party Transactions [table text block]

	March 31, 2017		December 31, 2016
Accounts receivable from related companies:
ETE	$	3	$	22
Sunoco LP	200		96
PES	8		6
FGT	17		15
Lake Charles LNG	3		4
Trans-Pecos Pipeline, LLC	1		1
Comanche Trail Pipeline, LLC	1		—
Other	56		65
Total accounts receivable from related companies:	$	289	$	209
Accounts payable to related companies:
Sunoco LP	$	168	$	20
FGT	—		1
Lake Charles LNG	3		3
Other	17		19
Total accounts payable to related companies:	$	188	$	43

	March 31, 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)

3 Months Ended

Mar. 31, 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 March 31,
	2017			2016
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	768		$	446
Intersegment revenues	48			112
	816			558
Interstate transportation and storage:
Revenues from external customers	231			254
Intersegment revenues	4			5
	235			259
Midstream:
Revenues from external customers	565			527
Intersegment revenues	1,072			565
	1,637			1,092
Liquids transportation and services:
Revenues from external customers	1,508			829
Intersegment revenues	114			90
	1,622			919
Investment in Sunoco Logistics:
Revenues from external customers	3,185			1,729
Intersegment revenues	34			48
	3,219			1,777
All other:
Revenues from external customers	638			696
Intersegment revenues	132			158
	770			854
Eliminations	(1,404		)	(978		)
Total revenues	$	6,895		$	4,481

Operating Segments [Member]

Segment Reporting Information [Line Items]

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

	Three Months Ended March 31,
	2017			2016
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	169		$	179
Interstate transportation and storage	265			292
Midstream	320			263
Liquids transportation and services	259			227
Investment in Sunoco Logistics	278			349
All other	123			102
Total	1,414			1,412
Depreciation, depletion and amortization	(560		)	(470		)
Interest expense, net	(339		)	(319		)
Gains (losses) on interest rate derivatives	5			(70		)
Non-cash unit-based compensation expense	(23		)	(19		)
Unrealized gains (losses) on commodity risk management activities	64			(63		)
Inventory valuation adjustments	2			(26		)
Adjusted EBITDA related to unconsolidated affiliates	(239		)	(219		)
Equity in earnings of unconsolidated affiliates	73			76
Other, net	22			16
Income before income tax expense (benefit)	$	419		$	318

Assets Segments [Member]

Segment Reporting Information [Line Items]

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

	March 31, 2017		December 31, 2016
Assets:
Intrastate transportation and storage	$	4,801	$	5,164
Interstate transportation and storage	10,066		10,833
Midstream	18,366		18,011
Liquids transportation and services	12,672		11,296
Investment in Sunoco Logistics	19,425		18,819
All other	7,107		6,068
Total assets	$	72,437	$	70,191

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Operations And Organization Operations And Organization (Details) - shares shares in Millions	1 Months Ended		3 Months Ended
	Mar. 31, 2016	Jul. 31, 2015	Mar. 31, 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%
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%
Sunoco LP Exchange [Member]
Stock Repurchased During Period, Shares		21
Sunoco LP Exchange [Member] | Sunoco GP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Dropdown of Sunoco LLC Interest [Member] | Sunoco, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	68.42%
Dropdown of Sunoco LLC Interest [Member] | Legacy Sunoco, Inc. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%

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Acquisitions and Contribution Transactions Narrative (Details) shares in Millions, $ in Millions	1 Months Ended			3 Months Ended
	Apr. 30, 2017 shares	Feb. 28, 2017 USD ($)	Mar. 31, 2016	Mar. 31, 2017 USD ($)	Feb. 01, 2017	Dec. 31, 2016 USD ($)
Goodwill				$ 3,915		$ 3,897
Intangible assets, net				5,506		$ 4,696
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross		$ 2,000
Sunoco, LLC [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			68.42%
Legacy Sunoco, Inc. [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Subsequent Event [Member] | SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5
Sale of Stock, Number of Shares Issued in Transaction | shares	845
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 Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired					49.00%
Sunoco Logistics [Member] | Permian Express Partners LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		85.00%
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		40.00%
ETP [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		60.00%
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%
Customer Relationships [Member] | Sunoco Logistics [Member]
Increase (Decrease) in Intangible Assets, Current				$ 547

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Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash and Cash Equivalents [Abstract]
Accounts receivable	$ (23)	$ (9)
Accounts receivable from related companies	(44)	90
Inventories	168	(11)
Other current assets	43	(99)
Other non-current assets, net	(18)	11
Accounts payable	(88)	51
Accounts payable to related companies	120	(2)
Accrued and other current liabilities	(139)	4
Other non-current liabilities	(2)	21
Derivative assets and liabilities, net	(32)	88
Net change in operating assets and liabilities, net of effects of acquisition	$ (15)	$ 144

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Cash And Cash Equivalents Non-Cash Investing and Financing Activities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 832	$ 826
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	5
NON-CASH FINANCING ACTIVITIES:
Capital Contributions from Noncontrolling Interest	$ 988	$ 0

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Inventories (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Inventory, Gross [Abstract]
Natural gas and NGLs	$ 474	$ 699
Crude oil	784	683
Refined products	86	113
Spare parts and other	202	217
Total inventories	$ 1,546	$ 1,712

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Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Fair Value Measurements [Abstract]
Transfers between levels in fair value hierarchy	$ 0
Aggregate fair value of long-term debt	33,090	$ 33,850
Long-term Debt	$ 32,040	$ 32,930

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Fair Value Measurements Fair Value Heigharchy (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Liability, Fair Value, Gross Liability	$ (349)	$ (666)
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	152	362
Assets, Fair Value Disclosure, Recurring	152	362
Interest rate derivatives, Liabilities	(188)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	(161)	(472)
Liabilities, Fair Value Disclosure, Recurring	(349)	(666)
Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	141	355
Assets, Fair Value Disclosure, Recurring	141	355
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(152)	(464)
Liabilities, Fair Value Disclosure, Recurring	(152)	(464)
Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	11	7
Assets, Fair Value Disclosure, Recurring	11	7
Interest rate derivatives, Liabilities	(188)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(9)	(8)
Liabilities, Fair Value Disclosure, Recurring	(197)	(201)
Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Assets, Fair Value Disclosure, Recurring	0	0
Interest rate derivatives, Liabilities	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	0	0
Liabilities, Fair Value Disclosure, Recurring	0	(1)
Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	7	14
Price Risk Derivative Liabilities, at Fair Value	(10)	(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	7	14
Price Risk Derivative Liabilities, at Fair Value	(10)	(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	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value	(1)	(3)
Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		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
Price Risk Derivative Liabilities, at Fair Value	(1)	(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	0
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	30	96
Price Risk Derivative Liabilities, at Fair Value	(42)	(149)
Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	30	96
Price Risk Derivative Liabilities, at Fair Value	(42)	(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	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Natural Gas [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	0
Commodity Derivatives - Natural Gas [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	0
Commodity Derivatives - Natural Gas [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	0
Commodity Derivatives - Natural Gas [Member] | Options - Calls [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, 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
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
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
Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		4
Price Risk Derivative Liabilities, at Fair Value	(8)	(5)
Commodity Derivatives - Power [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		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		4
Price Risk Derivative Liabilities, at Fair Value	(8)	(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	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	7	1
Price Risk Derivative Liabilities, at Fair Value		(1)
Commodity Derivatives - Power [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		(1)
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	7	0
Price Risk Derivative Liabilities, at Fair Value		0
Commodity Derivatives - Power [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	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	91	233
Price Risk Derivative Liabilities, at Fair Value	(88)	(273)
Commodity Derivatives - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	91	233
Price Risk Derivative Liabilities, at Fair Value	(88)	(273)
Commodity Derivatives - NGLs [Member] | Forward Swaps [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 - NGLs [Member] | Forward Swaps [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	(3)	(17)
Commodity Derivatives - Refined Products [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value	(3)	(17)
Commodity Derivatives - Refined Products [Member] | Future [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 - 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	0
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	12	9
Price Risk Derivative Liabilities, at Fair Value	(9)	(13)
Commodity Derivatives - Crude [Member] | Future [Member] | Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	12	9
Price Risk Derivative Liabilities, at Fair Value	(9)	(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	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	$ 0

XML

Net Income Per Limited Partner Unit Reconciliation of Basic and Diluted EPU (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net income		$ 364	$ 376
Less: Income attributable to noncontrolling interest		40	65
Net income, net of noncontrolling interest		324	311
General Partner’s interest in net income		206	297
Class H Unitholder’s interest in net income		98	79
Class I Unitholder’s interest in net income		0	2
Common Unitholders’ interest in net income (loss)		20	(67)
Additional earnings allocated to General Partner		(3)	(3)
Distributions on employee unit awards, net of allocation to General Partner		(7)	(5)
Net income (loss) available to Common Unitholders		$ 10	$ (75)
Weighted average Common Units – basic (1)	[1]	548.2	490.2
Diluted net income (loss) available to Common Unitholders		$ 10	$ (75)
Dilutive effect of unvested employee unit awards		1.4	0.0
Weighted average Common Units – diluted (1)	[1]	549.6	490.2
Basic net income (loss) per Common Unit		$ 0.02	$ (0.15)
Diluted net income (loss) per Common Unit		$ 0.02	$ (0.15)

[1] Excludes Common Units owned by the Partnership’s consolidated subsidiaries.

XML

Debt Obligations Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Jan. 31, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Repayments of Long-term Debt		$ 7,216	$ 3,914
Proceeds from Issuance of Long-term Debt	$ 1,480	6,366	$ 2,938
ETP [Member] | ETP Revolving Credit Facility, due November 2019 [Member]
Line of Credit Facility, Current Borrowing Capacity		3,750
Long-term Line of Credit		389
Sunoco Logistics [Member] | Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member]
Line of Credit Facility, Current Borrowing Capacity		2,500
Long-term Line of Credit		740
Commercial Paper		128
Line of Credit Facility, Maximum Borrowing Capacity		3,250
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		157
Line of Credit Facility, Maximum Borrowing Capacity		400
5.75% Senior Notes, due 2017 [Member] | Sunoco [Member]
Repayments of Long-term Debt	400
4.20% Senior Notes due April 2027 [Member]
Senior Notes	$ 600
Debt Instrument, Interest Rate, Stated Percentage	4.20%
5.30% Senior Notes due April 2047 [Member]
Senior Notes	$ 900
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | Sunoco Logistics [Member]
Line of Credit Facility, Current Borrowing Capacity				$ 1,000
Long-term Line of Credit				$ 630
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Long-term Line of Credit		$ 2,500

XML

Series A Preferred Units (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended	3 Months Ended
	Jan. 31, 2017	Mar. 31, 2017	Mar. 31, 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

XML

Equity Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended		3 Months Ended
	Feb. 28, 2017	Jan. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Proceeds from Sale of Equity Method Investments			$ 0		$ 2,200
Common units issued in connection with the distribution reinvestment plan			1.9
Net gains from subsidiary common unit issuances			$ 0		5
Proceeds from Issuance of Common Limited Partners Units			826		$ 363
Noncontrolling Interest, Increase from Sale of Parent Equity Interest			$ 2,000
Sunoco Logistics [Member]
Rate				$ 0.52
Post-Merger ETP [Member]
Rate			$ 0.5350
Distribution Made to Limited Partner, Distribution Date			May 15, 2017
Distribution Made to Limited Partner, Date of Record			May 10, 2017
ETP [Member]
Rate				1.0550
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement			$ 194
Stock Issued During Period, Value, Dividend Reinvestment Plan			$ 71
Partners' Capital Account, Units, Sold in Private Placement		15.8
Proceeds from Issuance of Private Placement		$ 568
PennTex [Member]
Rate			$ 0.2950	$ 0.2950
Distribution Made to Limited Partner, Distribution Date			May 12, 2017	Feb. 14, 2017
Distribution Made to Limited Partner, Date of Record			May 05, 2017	Feb. 07, 2017
Equity Distribution Agreement [Member] | ETP [Member]
Fees and Commissions			$ 2
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross	$ 2,000
Noncontrolling Interest, Increase from Sale of Parent Equity Interest			$ 1,260
Sunoco Logistics [Member] | ETP [Member]
Distribution Made to Limited Partner, Distribution Date				Feb. 14, 2017
Minimum [Member] | PennTex [Member]
Rate			$ 0.2750

XML

Equity Common Unit Activity (Details) - shares shares in Millions	1 Months Ended	3 Months Ended
	Jan. 31, 2017	Mar. 31, 2017
Number of common units at December 31, 2016	529.9	529.9
Common units issued in connection with equity distribution agreements		5.4
Common units issued in connection with the distribution reinvestment plan		1.9
Number of common units at March 31, 2017		553.0
ETP [Member]
Partners' Capital Account, Units, Sold in Private Placement	15.8

XML

Equity Quarterly Distributions Of Available Cash (Details) - $ / shares	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
PennTex [Member]
Distribution Made to Member or Limited Partner [Line Items]
Record Date	May 05, 2017	Feb. 07, 2017
Payment Date	May 12, 2017	Feb. 14, 2017
Rate	$ 0.2950	$ 0.2950
ETP [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate		1.0550
Sunoco Logistics [Member]
Distribution Made to Member or Limited Partner [Line Items]
Rate		$ 0.52

XML

Equity AOCI (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 4	$ 2
Foreign currency translation adjustment	(5)	(5)
Actuarial gain related to pensions and other postretirement benefits	5	7
Investments in unconsolidated affiliates, net	4	4
Total AOCI, net of tax	$ 8	$ 8

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended
	Jan. 31, 2012 USD ($)	Mar. 31, 2017 USD ($) sites	Mar. 31, 2016 USD ($)	Feb. 01, 2017 USD ($)	Dec. 31, 2016 USD ($)
Maximum lease expiration year		Dec. 31, 2034
Loss contingency accrual, at carrying value		$ 94,000,000			$ 77,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		0
Accrual for Environmental Loss Contingencies		$ 316,000,000			$ 309,000,000
Sites where remediation operations are responsibility of third parties | sites		9
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		$ 595,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		319,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		$ 536,000,000
AmeriGas [Member]
Contingent Residual Support Agreement, Amount	$ 1,550,000,000
Debt Instrument, Interest Rate, Stated Percentage		7.00%
Business Combination, Contingent Consideration, Liability				$ 102,000,000
Sunoco LP | 6.375% Senior Notes due April 2023 [Member]
Senior Notes		$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.375%
Sunoco LP | 6.25% Senior Notes due 2021 [Member]
Senior Notes		$ 800,000,000
Debt Instrument, Interest Rate, Stated Percentage		6.25%
Sunoco LP | Term loan due 2019 [Member]
Senior Notes		$ 2,035,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		6
Payments for Environmental Liabilities		$ 2,000,000	$ 6,000,000
Proposed Environmental Penalty		$ 200,000
Sunoco, Inc. [Member] | Multidistrict Legislation [Member]
Loss Contingency, Pending Claims, Number		4
Sunoco [Member]
Sites where remediation operations are responsibility of third parties		50
Sunoco Logistics [Member]
Payments for Environmental Liabilities		$ 100,000
Proposed Environmental Penalty		$ 100,000

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Operating Leases, Rental Expense (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Rental expense	$ 20	$ 18

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Environmental Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Environmental Exit Cost [Line Items]
Current	$ 28	$ 26
Non-current	288	283
Total environmental liabilities	$ 316	$ 309

XML

Derivative Assets And Liabilities Outstanding Commodity Derivatives (Details)		3 Months Ended	12 Months Ended
		Mar. 31, 2017 barrels Megawatt bbl MMbtu	Dec. 31, 2016 barrels Megawatt bbl MMbtu
WTI Crude Oil [Member]
Term Of Commodity Derivatives		2017
WTI Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2017
WTI Crude Oil [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | bbl		(1,418,000)	(617,000)
Natural Gas Liquids [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]
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		(1,827,400)	(5,786,627)
Power [Member] | Forwards Swaps [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt		(225,480)	(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		(447,200)	(186,400)
Power [Member] | Future [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | Megawatt		(58,000)
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			(50,400)
Power [Member] | Options - Puts [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume | Megawatt		(67,200)
Natural Gas [Member]
Term Of Commodity Derivatives		2017
Natural Gas [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives		2017
Natural Gas [Member] | Fixed Swaps/Futures [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		(51,102,500)	(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		(13,877,500)	(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		(80,000)
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
Natural Gas [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume			(22,492,489)
Natural Gas [Member] | Forward Physical Contracts [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume		(16,763,209)
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		(13,877,500)	(36,370,000)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		(5,247,500)
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		(13,877,500)	(36,370,000)
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member]
Term Of Commodity Derivatives			2017
Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | Trading [Member] | Mark-To-Market Derivatives [Member] | Long [Member]
Notional Volume	[1]	(8,372,500)	(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
Natural Gas [Member] | Swing Swaps IFERC [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume		(12,185,000)	(5,662,500)
Refined Products [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]
Term Of Commodity Derivatives			2017
Refined Products [Member] | Future [Member] | Non Trading [Member] | Mark-To-Market Derivatives [Member] | Short [Member]
Notional Volume | barrels		(1,217,000)	(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		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016
July 2017 [Member]
Notional Amount	[1]	$ 500	$ 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]	$ 200	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 4.00% 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]	$ 200	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.25% 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	Mar. 31, 2017	Dec. 31, 2016
Total derivatives assets	$ 152	$ 362
Total derivatives liabilities	(349)	(666)
Designated as Hedging Instrument [Member]
Total derivatives assets	0	0
Total derivatives liabilities	(2)	(4)
Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits)
Total derivatives assets	0	0
Total derivatives liabilities	(2)	(4)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	152	362
Total derivatives liabilities	(347)	(662)
Not Designated as Hedging Instrument [Member] | Commodity derivatives (margin deposits)
Total derivatives assets	139	338
Total derivatives liabilities	(145)	(416)
Not Designated as Hedging Instrument [Member] | Commodity derivatives
Total derivatives assets	13	24
Total derivatives liabilities	(14)	(52)
Not Designated as Hedging Instrument [Member] | Interest rate derivatives
Total derivatives assets	0	0
Total derivatives liabilities	(188)	(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	Mar. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 152	$ 362
Derivative Liability, Fair Value, Gross Liability	(349)	(666)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(6)	(4)
Derivative Liability, Fair Value, Amount Offset Against Collateral	6	4
Derivative Asset, Collateral, Obligation to Return Cash, Offset	(133)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	133	338
Derivative Asset, Fair Value, Net	13	20
Derivative Liability, Fair Value, Net	(210)	(324)
Without offsetting agreements [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(188)	(194)
OTC Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	13	24
Derivative Liability, Fair Value, Gross Liability	(14)	(52)
Broker cleared derivative contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	139	338
Derivative Liability, Fair Value, Gross Liability	$ (147)	$ (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
	Mar. 31, 2017	Mar. 31, 2016
Commodity derivatives	$ (4)	$ (4)
Commodity Derivatives [Member]
Commodity derivatives	$ (4)	$ (4)

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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
	Mar. 31, 2017	Mar. 31, 2016
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ (4)	$ (4)
Amount of Gain/(Loss) Recognized in Income on Derivatives	7	(74)
Gains (losses) on interest rate derivatives	5	(70)
Commodity Derivatives - Trading [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	11	(9)
Commodity derivatives
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	(4)	(4)
Amount of Gain/(Loss) Recognized in Income on Derivatives	(10)	5
Other Income (Expenses) [Member] | Embedded Derivatives in Preferred Units [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 1	$ 0

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Related Party Transactions Affiliated Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Related Party Transactions [Abstract]
Affiliated revenues	$ 118	$ 74

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Related Party Transactions Related Party A/R and A/P (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Total accounts receivable from related companies:	$ 289	$ 209
Total accounts payable to related companies:	188	43
Long-term notes payable – related companies	0	(250)
Net Related Party Receivable (Payable)	87	(163)
ETE
Total accounts receivable from related companies:	3	22
Sunoco LP
Notes Receivable, Related Parties, Noncurrent	87	87
Total accounts receivable from related companies:	200	96
Total accounts payable to related companies:	168	20
PES
Total accounts receivable from related companies:	8	6
FGT
Total accounts receivable from related companies:	17	15
Total accounts payable to related companies:	0	1
Lake Charles LNG
Total accounts receivable from related companies:	3	4
Total accounts payable to related companies:	3	3
Trans-Pecos Pipeline, LLC
Total accounts receivable from related companies:	1	1
Comanche Trail Pipeline, LLC [Member]
Total accounts receivable from related companies:	1	0
Other
Total accounts receivable from related companies:	56	65
Total accounts payable to related companies:	17	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
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Revenues	$ 6,895	$ 4,481
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Revenues	816	558
Intrastate transportation and storage | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	768	446
Intrastate transportation and storage | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	48	112
Interstate transportation and storage
Segment Reporting Information [Line Items]
Revenues	235	259
Interstate transportation and storage | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	231	254
Interstate transportation and storage | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	4	5
Midstream
Segment Reporting Information [Line Items]
Revenues	1,637	1,092
Midstream | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	565	527
Midstream | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	1,072	565
Liquids transportation and services
Segment Reporting Information [Line Items]
Revenues	1,622	919
Liquids transportation and services | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	1,508	829
Liquids transportation and services | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	114	90
Investment in Sunoco Logistics
Segment Reporting Information [Line Items]
Revenues	3,219	1,777
Investment in Sunoco Logistics | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	3,185	1,729
Investment in Sunoco Logistics | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	34	48
All other
Segment Reporting Information [Line Items]
Revenues	770	854
All other | Revenues from external customers
Segment Reporting Information [Line Items]
Revenues	638	696
All other | Intersegment revenues
Segment Reporting Information [Line Items]
Revenues	132	158
Eliminations
Segment Reporting Information [Line Items]
Revenues	$ (1,404)	$ (978)

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Reportable Segments Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,414	$ 1,412
Depreciation, depletion and amortization	(560)	(470)
Interest expense, net	(339)	(319)
Gains (losses) on interest rate derivatives	5	(70)
Non-cash unit-based compensation expense	(23)	(19)
Unrealized gains (losses) on commodity risk management activities	64	(63)
Inventory valuation adjustments	2	(26)
Adjusted EBITDA related to unconsolidated affiliates	(239)	(219)
Equity in earnings of unconsolidated affiliates	73	76
Other, net	22	16
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	419	318
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	169	179
Interstate transportation and storage
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	265	292
Midstream
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	320	263
Liquids transportation and services
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	259	227
Investment in Sunoco Logistics
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	278	349
All other
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 123	$ 102

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Reportable Segments Segment Assets (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets	$ 72,437	$ 70,191
Intrastate transportation and storage
Segment Reporting Information [Line Items]
Assets	4,801	5,164
Interstate transportation and storage
Segment Reporting Information [Line Items]
Assets	10,066	10,833
Midstream
Segment Reporting Information [Line Items]
Assets	18,366	18,011
Liquids transportation and services
Segment Reporting Information [Line Items]
Assets	12,672	11,296
Investment in Sunoco Logistics
Segment Reporting Information [Line Items]
Assets	19,425	18,819
All other
Segment Reporting Information [Line Items]
Assets	$ 7,107	$ 6,068

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Reportable Segments Reportable Segments Narrative (Details) - Sunoco LP shares in Millions	Mar. 31, 2017 shares
Investments in and Advances to Affiliates, Balance, Shares	43.5
Equity Method Investment, Ownership Percentage	43.70%