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 1-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)

Delaware	30-0108820
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

At April 28, 2017, the registrant had 1,079,185,030 Common Units outstanding.

FORM 10-Q

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Consolidated Balance Sheets	1
Consolidated Statements of Operations	3
Consolidated Statements of Comprehensive Income	4
Consolidated Statement of Equity	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	50
ITEM 4. CONTROLS AND PROCEDURES	52
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	53
ITEM 1A. RISK FACTORS	53
ITEM 6. EXHIBITS	54
SIGNATURE	55

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity,” the “Partnership” or “ETE”) in periodic press releases and some oral statements of Energy Transfer Equity 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,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2016 filed with the Securities and Exchange Commission on February 24, 2017 and “Part II — Item 1A. Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2016 and in this Quarterly Report on Form 10-Q for the quarter ended March 31, 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
Bcf	billion cubic feet
Btu	British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
Convertible Units	Series A Convertible Preferred Units in ETE
EPA	Environmental Protection Agency
ETP GP	Energy Transfer Partners GP, L.P., the general partner of ETP, for the periods presented herein
ETP Preferred Units	ETP’s Series A Convertible Preferred Units
Exchange Act	Securities Exchange Act of 1934
FERC	Federal Energy Regulatory Commission
GAAP	accounting principles generally accepted in the United States of America
IDRs	incentive distribution rights
Lake Charles LNG	Lake Charles LNG Company, LLC
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas
Lone Star	Lone Star NGL 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

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OSHA	Federal Occupational Safety and Health Act
OTC	over-the-counter
Panhandle	Panhandle Eastern Pipe Line Company, LP
PCBs	polychlorinated biphenyl
PES	Philadelphia Energy Solutions
PennTex	PennTex Midstream Partners, LP
Regency	Regency Energy Partners LP
SEC	Securities and Exchange Commission
Southern Union	Southern Union Company
Sunoco GP	Sunoco GP LLC, the general partner of Sunoco LP
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
WMB	The Williams Companies, Inc.

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, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	March 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	370		$	483
Accounts receivable, net	3,485			3,557
Accounts receivable from related companies	72			47
Inventories	2,065			2,291
Derivative assets	9			21
Other current assets	513			586
Total current assets	6,514			6,985
Property, plant and equipment	65,788			63,721
Accumulated depreciation and depletion	(8,821		)	(8,283		)
	56,967			55,438
Advances to and investments in unconsolidated affiliates	3,103			3,040
Other non-current assets, net	826			818
Intangible assets, net	6,837			5,992
Goodwill	6,750			6,738
Total assets	$	80,997		$	79,011

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)

	March 31, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,363		$	3,502
Accounts payable to related companies	33			42
Derivative liabilities	126			172
Accrued and other current liabilities	2,304			2,367
Current maturities of long-term debt	392			1,194
Total current liabilities	6,218			7,277
Long-term debt, less current maturities	42,583			42,608
Long-term notes payable – related companies	—			250
Non-current derivative liabilities	72			76
Deferred income taxes	5,130			5,112
Other non-current liabilities	1,237			1,123
Commitments and contingencies
Preferred units of subsidiary	—			33
Redeemable noncontrolling interests	15			15
Equity:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,389		)	(1,871		)
Series A Convertible Preferred Units	245			180
Total partners’ capital (deficit)	(1,147		)	(1,694		)
Noncontrolling interest	26,889			24,211
Total equity	25,742			22,517
Total liabilities and equity	$	80,997		$	79,011

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

2

ENERGY TRANSFER EQUITY, L.P. 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	1,546			940
Crude sales	2,347			1,209
Gathering, transportation and other fees	1,065			1,003
Refined product sales	4,155			2,539
Other	1,122			1,166
Total revenues	11,247			7,695
COSTS AND EXPENSES
Cost of products sold	8,991			5,623
Operating expenses	673			641
Depreciation, depletion and amortization	661			562
Selling, general and administrative	197			168
Total costs and expenses	10,522			6,994
OPERATING INCOME	725			701
OTHER INCOME (EXPENSE)
Interest expense, net	(486		)	(427		)
Equity in earnings of unconsolidated affiliates	87			61
Losses on extinguishments of debt	(25		)	—
Gains (losses) on interest rate derivatives	5			(70		)
Other, net	19			16
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	325			281
Income tax expense (benefit)	35			(55		)
NET INCOME	290			336
Less: Net income attributable to noncontrolling interest	51			24
NET INCOME ATTRIBUTABLE TO PARTNERS	239			312
General Partner’s interest in net income	1			1
Convertible Unitholders’ interest in income	6			—
Limited Partners’ interest in net income	$	232		$	311
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.22		$	0.30
Diluted	$	0.21		$	0.30

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)

	Three Months Ended March 31,
	2017			2016
Net income	$	290		$	336
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	290			322
Less: Comprehensive income attributable to noncontrolling interest	51			10
Comprehensive income attributable to partners	$	239		$	312

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2017

(Dollars in millions)

(unaudited)

	General Partner			Common Unitholders			Series A Convertible Preferred Units		Accumulated Other Comprehensive Income (Loss)		Non-controlling Interest			Total
Balance, December 31, 2016	$	(3	)	$	(1,871	)	$	180	$	—	$	24,211		$	22,517
Distributions to partners	(1		)	(250		)	—		—		—			(251		)
Distributions to noncontrolling interest	—			—			—		—		(752		)	(752		)
Distributions reinvested	—			(58		)	58		—		—			—
Subsidiary units issued	—			(52		)	—		—		351			299
Issuance of common units	—			568			—		—		—			568
Capital contributions received from noncontrolling interest	—			—			—		—		1,094			1,094
Sale of Bakken Pipeline interest	—			42			—		—		1,958			2,000
Other, net	—						1		—		(24		)	(23		)
Net income	1			232			6		—		51			290
Balance, March 31, 2017	$	(3	)	$	(1,389	)	$	245	$	—	$	26,889		$	25,742

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Three Months Ended March 31,
	2017			2016
OPERATING ACTIVITIES
Net income	$	290		$	336
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	661			562
Deferred income taxes	34			(46		)
Amortization included in interest expense	5			(3		)
Unit-based compensation expense	27			1
(Gains) losses on disposal of assets	6			3
Losses on extinguishments of debt	25			—
Inventory valuation adjustments	12			13
Equity in earnings of unconsolidated affiliates	(87		)	(61		)
Distributions from unconsolidated affiliates	46			84
Distributions on unvested awards	(9		)	(7		)
Other non-cash	(60		)	13
Net change in operating assets and liabilities, net of effects of acquisition	(57		)	90
Net cash provided by operating activities	893			985
INVESTING ACTIVITIES
Proceeds from Bakken Pipeline Transaction	2,000			—
Proceeds from (cash paid for) acquisitions, net of cash received	(330		)	(2		)
Capital expenditures, excluding allowance for equity funds used during construction	(1,450		)	(1,948		)
Contributions in aid of construction costs	6			10
Contributions to unconsolidated affiliates	(111		)	(31		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	90			21
Proceeds from the sale of assets	1			10
Change in restricted cash	—			(1		)
Other	(3		)	(1		)
Net cash provided by (used in) investing activities	203			(1,942		)
FINANCING ACTIVITIES
Proceeds from borrowings	9,000			5,750
Repayments of long-term debt	(9,809		)	(4,422		)
Cash paid on affiliate notes	(268		)	—
Subsidiary units issued for cash	299			664
Units issued for cash	568			—
Distributions to partners	(251		)	(299		)
Debt issuance costs	(53		)	(19		)
Distributions to noncontrolling interest	(752		)	(658		)
Redemption of Series A Preferred Units	(53		)	—
Capital contributions received from noncontrolling interest	106			132
Other, net	4			10
Net cash provided by financing activities	(1,209		)	1,158
Increase (decrease) in cash and cash equivalents	(113		)	201
Cash and cash equivalents, beginning of period	483			606
Cash and cash equivalents, end of period	$	370		$	807

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

In April 2017, Energy Transfer Partners, L.P. (“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.

Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P.

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 ETE presented herein include the results of operations of:

• the Parent Company;

• our controlled subsidiaries, ETP and Sunoco LP;

• consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDR interests in ETP and Sunoco LP; and

• our wholly-owned subsidiary, Lake Charles LNG.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 14 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

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• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

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 2017 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.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP or Sunoco LP (excluding transactions with the Parent Company) as capital transactions.

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.

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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 DIVESTURES

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. 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.

Prior to the merger of ETP and Sunoco Logistics, ETE owned 18.4 million ETP common units (representing 3.3% of the total outstanding ETP common units), 81 million ETP Class H units and 100 ETP Class I units. In connection with the merger, the ETP Class H units were cancelled, and ETE now owns 27.5 million Post-Merger ETP common units (representing 2.5% of the total outstanding Post-Merger ETP common units) and 100 Post-Merger ETP Class I units. The Post-Merger ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the ETP Class I units.

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

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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 $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.

Sunoco LP Convenience Store Sale

On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,100 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”) . The transaction is expected to close in the second half of 2017.

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 by uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Non-cash investing activities were as follows:

	Three Months Ended March 31,
	2017			2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	833		$	829
Losses from subsidiary common unit issuances, net	(52		)	(12		)
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	455		540
Other	352		369
Total inventories	$	2,065	$	2,291

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ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventories stored in our Bammel storage facility. 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 $44.34 billion and $42.98 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations was $45.05 billion and $43.80 billion, respectively. The fair value of our consolidated debt obligations is Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.

We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP 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 the 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:
Forwards	7			—			7			—
Options — Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	91			91			—			—
Refined Products — Futures	2			2			—			—
Crude – Futures	12			12			—			—
Total commodity derivatives	154			143			11			—
Total assets	$	154		$	143		$	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	(5		)	(5		)	—			—
Crude — Futures	(9		)	(9		)	—			—
Total commodity derivatives	(163		)	(154		)	(9		)	—
Total liabilities	$	(351	)	$	(154	)	$	(197	)	$	—

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				Fair Value Measurements at December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX	14			14			—			—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Contracts	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options — Calls	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	233			233			—			—
Refined Products — Futures	2			2			—			—
Crude - Futures	9			9			—			—
Total commodity derivatives	363			356			7			—
Total assets	$	363		$	356		$	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	(23		)	(23		)	—			—
Crude - Futures	(13		)	(13		)	—			—
Total commodity derivatives	(478		)	(470		)	(8		)	—
Total liabilities	$	(672	)	$	(470	)	$	(201	)	$	(1	)

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6. NET INCOME PER LIMITED PARTNER UNIT

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

	Three Months Ended March 31,
	2017		2016
Net Income	$	290	$	336
Less: Income attributable to noncontrolling interest	51		24
Net Income, net of noncontrolling interest	239		312
Less: General Partner’s interest in income	1		1
Less: Convertible Unitholders’ interest in income	6		—
Income available to Limited Partners	$	232	$	311
Basic Income per Limited Partner Unit:
Weighted average limited partner units	1,075.2		1,044.8
Basic income per Limited Partner unit	$	0.22	$	0.30
Diluted Income per Limited Partner Unit:
Income available to Limited Partners	$	232	$	311
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	6		—
Diluted income available to Limited Partners	$	238	$	311
Weighted average limited partner units	1,075.2		1,044.8
Dilutive effect of unconverted unit awards and Convertible Units	63.8		—
Diluted weighted average limited partner units	1,139.0		1,044.8
Diluted income per Limited Partner unit	$	0.21	$	0.30

7. DEBT OBLIGATIONS

Parent Company Indebtedness

The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.

ETE Term Loan Facility

On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLP Merger, ETP , and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLP Merger, ETP, and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.4 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs

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in, immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.

Revolving Credit Facility

On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the Revolver Lenders have committed to provide advances up to an aggregate principal amount of $1.5 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of March 31, 2017, there were $1.15 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $351 million.

Subsidiary Indebtedness

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.

Sunoco LP Term Loan

Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of March 31, 2017, the balance on the term loan was $1.2 billion.

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.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility. As of March 31, 2017, the Sunoco LP credit facility had $761 million of outstanding borrowings and $21 million in standby letters of credit. The unused availability on the revolver at March 31, 2017 was $718 million.

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 and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2017.

8. REDEEMABLE 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

ETE

The changes in ETE common units and Convertible Units during the three months ended March 31,2017 were as follows:

	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2016	329.3	1,046.9
Issuance of common units	—	32.2
Outstanding at March 31, 2017	329.3	1,079.1

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ETE Equity Distribution Agreement

In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the three months endedMarch 31, 2017.

Series A Convertible Preferred Units

As of March 31, 2017, The Partnership had 329.3 million Series A Convertible Preferred Units outstanding with a carrying value of $245 million.

ETE January 2017 Private Placement and ETP Unit Purchase

In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 15.8 million newly issued ETP common units for approximately $568 million.

Repurchase Program

During the three months endedMarch 31, 2017, ETE did not repurchase any ETE common units under its current buyback program. As of March 31, 2017, $936 million remained available to repurchase under the current program.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the three months ended March 31, 2017, we recognized decreases in partners’ capital of $52 million.

ETP Common Unit Transactions

During the three months ended March 31,2017, ETP 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 ETP’s distribution reinvestment plan. In connection with the merger of ETP and Sunoco Logistics in April 2017, the distribution reinvestment plan was terminated.

Sunoco Logistics Common Unit Transactions

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

Sunoco LP Common Unit Transactions

During the three months ended March 31,2017, Sunoco LP received net proceeds of $33 million from the issuance of 1.3 million Sunoco LP common units pursuant to its equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. As of March 31, 2017, $295 million of Sunoco LP’s common units remained available to be issued under the equity distribution agreement.

Sunoco LP Series A Preferred Units

On March 30, 2017, the Partnership purchased Sunoco LP’s 12.0 million series A preferred units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.

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.

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Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016 (1)	February 7, 2017	February 21, 2017	$	0.2850
March 31, 2017 (1)	May 10, 2017	May 19, 2017	0.2850

⁽¹⁾  Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit.

Our distributions declared with respect to our Convertible Units subsequent to December 31, 2016 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 21, 2017	$	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100

ETP and Sunoco Logistics Quarterly Distributions of Available Cash

Following the merger of ETP and Sunoco Logistics in April 2017, the Post-Merger ETP partnership agreement contains distribution provisions consistent with those of Sunoco Logistics 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.

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

	Total Year
2017 (remainder)	$	499
2018	153
2019	128
Each year beyond 2019	33

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

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 13, 2017	February 21, 2017	$	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255

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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 loss related to pensions and other postretirement benefits	5			7
Investments in unconsolidated affiliates, net	4			4
Subtotal	8			8
Amounts attributable to noncontrolling interest	(8		)	(8		)
Total AOCI, net of tax	$	—		$	—

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.

NGL Pipeline Regulation

ETP has interests in NGL pipelines located in Texas and New Mexico. ETP 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 ETP’s 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 ETP’s 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.

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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates 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(1)	$	54		$	51
Less: Sublease rental income	(6		)	(7		)
Rental expense, net	$	48		$	44

⁽¹⁾  Includes contingent rentals totaling $5 million and $16 million for the three months ended March 31,2017 and 2016, respectively.

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

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

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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 claim related to its 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

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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

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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.

Litigation Filed By or Against WMB

On April 6, 2016, WMB filed a complaint against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG. WMB alleged that Defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates (the “Merger Agreement”) by issuing ETE’s Series A Convertible Preferred Units. According to WMB, the issuance of Convertible Units (the “Issuance”) violates various contractual restrictions on ETE’s actions between the execution and closing of the merger. WMB sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware WMB Litigation. The counterclaim asserts in general that WMB materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow WMB’s independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing the Texas WMB Litigation against Mr. Warren in the District Court of Dallas County, Texas.

On May 13, 2016, WMB filed a second lawsuit in the Delaware Court of Chancery against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (the “Second Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG. In general, WMB alleged that the defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion under Section 721 of the Tax Code (“721 Opinion”), a condition precedent to the closing of the merger, and (b) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. WMB asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions. WMB sought to expedite the second lawsuit, and ETE agreed to expedite both Delaware actions.

ETE also filed an answer and counterclaim in the Second Delaware WMB Litigation. In addition to the counterclaims previously asserted, ETE asserted that WMB materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the WMB board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger necessary to prevent the Form S-4 from being materially misleading, (c) failing to facilitate the financing of the merger, (d) failing to be reasonable with respect to its withholding of its consent to ETE’s offering of Series A Convertible Preferred Units, and (e) failing to use its reasonable best efforts to consummate the merger. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’s requests for injunctive relief. WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.

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Williams filed an amended complaint on September 16, 2016. In the amended complaint, Williams abandons its request for injunctive relief, including its request that the Court order the ETE Defendants to consummate the merger. Instead, Williams seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement.

The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016. In the amended counterclaim, the ETE Defendants seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.

On January 11, 2017, the Delaware Supreme Court held oral arguments on Williams’ appeal of the June 2016 trial. The Delaware Supreme Court affirmed the Court of Chancery on March 23, 2017 and denied Williams’ motion for reargument on April 5, 2017.

The parties are currently engaging in discovery in connection with their amended claims and counterclaims.

Unitholder Litigation Relating to the Issuance

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware. Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.

The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of Convertible Units.

The parties engaged in discovery, and Plaintiffs’ filed a consolidated amended complaint on August 29, 2016. In addition to the injunctive relief described above, Plaintiffs seek class-wide damages allegedly resulting from the Issuance.

On September 28, 2016, Defendants and Plaintiffs filed cross-motions for partial summary judgment. The Court held a hearing on the parties’ motions on November 9, 2016. On February 28, 2017, the Court denied both motions for partial summary judgment. The parties are continuing to engage in discovery.

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.

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Environmental Matters

Our operations are subject to extensive federal, 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.  Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products.  As a result, there can be no assurance that significant costs and liabilities will not be incurred.  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 remedial obligations, the issuance of injunctions 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 ofMarch 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.

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

	March 31, 2017		December 31, 2016
Current	$	32	$	31
Non-current	321		318
Total environmental liabilities	$	353	$	349

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, the Partnership recorded $4 million and $8 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 its 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.

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, our subsidiaries 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.

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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 futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment. 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 and Crude (Bbls) — Forwards/Swaps	(1,827,400	)	2017	(5,786,627	)	2017
Refined Products (Bbls) — Futures	(1,492,000	)	2017	(3,144,000	)	2017
Corn (Bushels) — Futures	(730,000	)	2017	1,580,000		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 anticipated debt issuances.

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

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

Credit Risk

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

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

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

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

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Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	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	15		25		(16		)	(58		)
Interest rate derivatives	—		—		(188		)	(193		)
Embedded derivatives in the ETP Preferred Units	—		—		—			(1		)
	154		363		(349		)	(668		)
Total derivatives	$	154	$	363	$	(351	)	$	(672	)

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)	15			25			(16		)	(58		)
Broker cleared derivative contracts	Other current assets	139			338			(147		)	(420		)
Total gross derivatives		154			363			(351		)	(672		)
Less 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		$	15		$	21		$	(212	)	$	(330	)

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	2		8
Interest rate derivatives	Gains (losses) on interest rate derivatives	5		(70		)
Embedded derivatives	Other, net	1		—
Total		$	19	$	(71	)

12. RELATED PARTY TRANSACTIONS

ETP previously had agreements with the Parent Company to provide services on its behalf and the behalf of other subsidiaries of the Parent Company, which included the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. These agreements have subsequently expired.

In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

In addition, ETE recorded sales with affiliates of $50 million and $81 million during the three months endedMarch 31, 2017 and 2016, respectively.

13.    REPORTABLE SEGMENTS

Our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

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The Investment in Sunoco LP segment reflects the results of Sunoco LP and the legacy Sunoco, Inc. retail business for the periods presented.

Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

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

The following tables present financial information by segment:

	Three Months Ended March 31,
	2017			2016
Segment Adjusted EBITDA:
Investment in ETP	$	1,414		$	1,412
Investment in Sunoco LP	155			159
Investment in Lake Charles LNG	44			44
Corporate and Other	(13		)	(37		)
Adjustments and Eliminations	(54		)	(57		)
Total	1,546			1,521
Depreciation, depletion and amortization	(661		)	(562		)
Interest expense, net	(486		)	(427		)
Unrealized gains (losses) on interest rate derivatives	5			(70		)
Non-cash unit-based compensation expense	(27		)	(1		)
Unrealized gains (losses) on commodity risk management activities	69			(60		)
Losses on extinguishments of debt	(25		)	—
Inventory valuation adjustments	(12		)	(13		)
Equity in earnings of unconsolidated affiliates	87			61
Adjusted EBITDA related to unconsolidated affiliates	(185		)	(162		)
Other, net	14			(6		)
Income before income tax expense (benefit)	$	325		$	281

	March 31, 2017			December 31, 2016
Assets:
Investment in ETP	$	72,437		$	70,191
Investment in Sunoco LP	8,454			8,701
Investment in Lake Charles LNG	1,540			1,508
Corporate and Other	660			711
Adjustments and Eliminations	(2,094		)	(2,100		)
Total assets	$	80,997		$	79,011

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	Three Months Ended March 31,
	2017			2016
Revenues:
Investment in ETP:
Revenues from external customers	$	6,807		$	4,434
Intersegment revenues	88			47
	6,895			4,481
Investment in Sunoco LP:
Revenues from external customers	4,391			3,212
Intersegment revenues	3			3
	4,394			3,215
Investment in Lake Charles LNG:
Revenues from external customers	49			49
Adjustments and Eliminations	(91		)	(50		)
Total revenues	$	11,247		$	7,695

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP and Lake Charles LNG.

Investment in ETP

	Three Months Ended March 31,
	2017		2016
Intrastate Transportation and Storage	$	768	$	446
Interstate Transportation and Storage	231		254
Midstream	565		527
Liquids Transportation and Services	1,508		829
Investment in Sunoco Logistics	3,185		1,729
All Other	638		696
Total revenues	6,895		4,481
Less: Intersegment revenues	88		47
Revenues from external customers	$	6,807	$	4,434

Investment in Sunoco LP

	Three Months Ended March 31,
	2017		2016
Retail operations	$	2,098	$	1,675
Wholesale operations	2,296		1,540
Total revenues	4,394		3,215
Less: Intersegment revenues	3		3
Revenues from external customers	$	4,391	$	3,212

Investment in Lake Charles LNG

Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling.

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14. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

(unaudited)

	March 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	3		$	2
Accounts receivable, net	2			—
Accounts receivable from related companies	57			55
Total current assets	62			57
Property, plant and equipment, net	35			36
Advances to and investments in unconsolidated affiliates	5,940			5,088
Intangible assets, net	—			1
Goodwill	9			9
Other non-current assets, net	19			10
Total assets	$	6,065		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	1
Accounts payable to related companies	3			22
Interest payable	80			66
Accrued and other current liabilities	3			3
Total current liabilities	86			92
Long-term debt, less current maturities	6,639			6,358
Long-term notes payable – related companies	485			443
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ capital:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,389		)	(1,871		)
Series A Convertible Preferred Units	245			180
Total partners’ capital (deficit)	(1,147		)	(1,694		)
Total liabilities and equity	$	6,065		$	5,201

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STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2017			2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(13	)	$	(37	)
OTHER INCOME (EXPENSE):
Interest expense, net	(83		)	(81		)
Equity in earnings of unconsolidated affiliates	361			430
Losses on extinguishments of debt	(25		)	—
Other, net	(1		)	—
NET INCOME	239			312
General Partner’s interest in net income	1			1
Convertible Unitholders’ interest in income	6			—
Limited Partners’ interest in net income	$	232		$	311

⁽¹⁾  Includes management fees paid by ETE to ETP, which management fees will no longer be paid subsequent to March 31, 2017.

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STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2017			2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	251		$	223
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(860		)	(65		)
Capital expenditures	—			(7		)
Net cash used in investing activities	(860		)	(72		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,017			105
Principal payments on debt	(1,733		)	—
Proceeds from affiliate	43			50
Distributions to partners	(251		)	(299		)
Units issued for cash	568			—
Debt issuance costs	(34		)	—
Net cash provided by (used in) financing activities	610			(144		)
INCREASE IN CASH AND CASH EQUIVALENTS	1			7
CASH AND CASH EQUIVALENTS, beginning of period	2			1
CASH AND CASH EQUIVALENTS, end of period	$	3		$	8

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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 our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 24, 2017. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. See Note 1 to the consolidated financial statements for information related to recent name changes of our subsidiaries.

OVERVIEW

At March 31, 2017, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 18.4 million ETP common units, 81 million ETP Class H units, 2.2 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, which currently are not entitled to distributions.

Our reportable segments are as follows:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

RECENT DEVELOPMENTS

ETE January 2017 Private Placement and ETP Unit Purchase

In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 15.8 million newly issued ETP common units.

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. 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.

Prior to the merger of ETP and Sunoco Logistics, ETE owned 18.4 million ETP common units (representing 3.3% of the total outstanding ETP common units), 81.0 ETP Class H units and 100 ETP Class I units. In connection with the merger, the ETP Class H units were cancelled, and ETE now owns 27.5 million Post-Merger ETP common units (representing 2.5% of the total outstanding Post-Merger ETP common units) and 100 Post-Merger ETP Class I units. The Post-Merger ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the ETP Class I units.

37

Sunoco LP Real Estate Sale

In January 2017, Sunoco LP launched a portfolio optimization plan to market and sell 99 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale in a ‘buy one, some or all’ format with bids due on March 7, 2017 for the operating sites and on April 4, 2017 for the surplus properties. Sunoco LP will review all bids before divesting any assets.

Sunoco LP Series A Preferred Units

On March 30, 2017, the Partnership purchased Sunoco LP’s 12,000,000 series A preferred units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units will be 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.

Sunoco LP Convenience Store Sale

On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale a portfolio of 1,112 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion. The transaction is expected to close in the second half of 2017.

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.

ETP 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.

Quarterly Cash Distribution

In April 2017, ETE announced its quarterly distribution of $0.285 per unit ($1.14 annualized) on ETE common units for the quarter ended March 31, 2017.

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Results of Operations

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

Consolidated Results

	Three Months Ended March 31,
	2017			2016			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,414		$	1,412		$	2
Investment in Sunoco LP	155			159			(4		)
Investment in Lake Charles LNG	44			44			—
Corporate and Other	(13		)	(37		)	24
Adjustments and Eliminations	(54		)	(57		)	3
Total	1,546			1,521			25
Depreciation, depletion and amortization	(661		)	(562		)	(99		)
Interest expense, net	(486		)	(427		)	(59		)
Gains (losses) on interest rate derivatives	5			(70		)	75
Non-cash unit-based compensation expense	(27		)	(1		)	(26		)
Unrealized gains (losses) on commodity risk management activities	69			(60		)	129
Losses on extinguishments of debt	(25		)	—			(25		)
Inventory valuation adjustments	(12		)	(13		)	1
Equity in earnings of unconsolidated affiliates	87			61			26
Adjusted EBITDA related to unconsolidated affiliates	(185		)	(162		)	(23		)
Other, net	14			(6		)	20
Income before income tax expense (benefit)	325			281			44
Income tax expense (benefit)	35			(55		)	90
Net income	$	290		$	336		$	(46	)

See the detailed discussion of Segment Adjusted EBITDA in “Segment Operating Results” below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2017 compared to the same periods last year increased primarily due to additional depreciation and amortization from assets recently placed in service.

Interest Expense, Net. Interest expense for the three months endedMarch 31, 2017 increased primarily due to the following:

• an increase of $36 million of expense recognized by Sunoco LP primarily attributable to the borrowings under Sunoco LP’s term loan agreement entered into on March 31, 2016, the issuance of our $800 million 6.250% senior notes on April 7, 2016, as well as the increase in borrowings under Sunoco LP’s revolving credit facility; and

• an increase of $20 million of expense recognized by ETP primarily due to recent debt issuances by ETP and its consolidated subsidiaries.

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

39

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 additional discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded during the three months endedMarch 31, 2017 and 2016, for the inventory associated with Sunoco LP and Sunoco Logistics as a result of commodity price changes between periods.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. Amounts reflected primarily include our proportionate share of such amounts related to Citrus, LLC, Fayetteville Express Pipeline LLC, PES, Midcontinent Express Pipeline LLC, RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP and others.

Other, net. Includes amortization of regulatory assets, certain acquisition related costs, other income and expense amounts, and non-cash expenses not included in the other reconciling items above.

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 $9 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.

Segment Operating Results

Investment in ETP

	Three Months Ended March 31,
	2017			2016			Change
Revenues	$	6,895		$	4,481		$	2,414
Cost of products sold	5,192			2,968			2,224
Gross margin	1,703			1,513			190
Unrealized (gains) losses on commodity risk management activities	(64		)	63			(127		)
Operating expenses, excluding non-cash compensation expense	(372		)	(348		)	(24		)
Selling, general and administrative, excluding non-cash compensation expense	(100		)	(85		)	(15		)
Inventory valuation adjustments	(2		)	26			(28		)
Adjusted EBITDA related to unconsolidated affiliates	239			219			20
Other	10			24			(14		)
Segment Adjusted EBITDA	$	1,414		$	1,412		$	2

Segment Adjusted EBITDA. For the three months endedMarch 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP decreased due to the net impact of the following:

• a decrease of $27 million in ETP’s interstate transportation and storage operations, primarily attributable to decreases in revenues on the Tiger pipeline and the Panhandle and Trunkline pipelines due to contract restructuring and lack of customer demand, respectively, and a decrease in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower margins on the Midcontinent Express pipeline due to a customer bankruptcy;

• a decrease of $71 million from Sunoco Logistics 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 segment 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

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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;

• a decrease of $10 million in ETP’s intrastate transportation and storage operations due to a decrease in transportation fees due to renegotiated contracts resulting in lower demand volumes beginning in the second quarter of 2016 on ETP’s ET Fuel pipeline offset by an increase in natural gas sales and other primarily due to higher realized gains from the buying and selling of gas along our system; offset by

• an increase of $32 million in ETP’s liquids transportation and services operations, primarily attributable to higher volumes transported out of all major producing regions, including the Permian, North Texas, Louisiana and the Eagle Ford, but declined slightly in Southeast Texas, along with the impact of favorable market conditions and the ramp-up of the fourth fractionator at Mont Belvieu;

• an increase of $57 million in ETP’s midstream operations primarily due to higher volumes in the Permian region and due to higher crude oil and NGL prices, partially offset by an increase in operating expenses primarily due to recent acquisitions;

• an increase of approximately $21 million in ETP’s all other operations, primarily due to an increase of $22 million in Adjusted EBITDA related to ETP’s 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-rated expenses. The 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.

Unrealized Gains (Losses )on Commodity Risk Management Activities. Unrealized losses on commodity risk management activities primarily reflected the net impact from unrealized gains and losses on natural gas storage and non-storage derivatives, as well as fair value adjustments to inventory. For the three months ended March 31, 2017 compared to the same periods last year, the changes included a decrease of $37 million related to Sunoco Logistics, a decrease of $35 million related to ETP’s liquids transportation and services operations, a decrease of $23 million related to ETP’s intrastate transportation and storage operations, a decrease of $16 million related to ETP’s all other operations and a decrease of $16 million for the three months ended March 31, 2017, related to ETP’s midstream operations.

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.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three months ended March 31,2017 compared to the same periods last year, ETP’s operating expenses increased $24 million primarily due to increased costs associated with ETP’s fourth fractionator at Mont Belvieu and new pipelines placed in service.

Adjusted EBITDA Related to Unconsolidated Affiliates. Adjusted EBITDA related to unconsolidated affiliates for the three months ended March 31,2017 decreased $20 million compared to the same period last year primarily due to a $3 million decrease in adjusted EBITDA related to Sunoco LP as a result of the impact of refining crack spreads offset by a $22 million increase related to PES.

Investment in Sunoco LP

	Three Months Ended March 31,
	2017			2016			Change
Revenues	$	4,394		$	3,215		$	1,179
Cost of products sold	3,891			2,704			1,187
Gross margin	503			511			(8		)
Operating expenses, excluding non-cash compensation expense	(297		)	(282		)	(15		)
Selling, general and administrative, excluding non-cash compensation expense	(60		)	(55		)	(5		)
Inventory valuation adjustments	14			(12		)	26
Unrealized gains on commodity risk management activities	(5		)	(3		)	(2		)
Segment Adjusted EBITDA	$	155		$	159		$	(4	)

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Segment Adjusted EBITDA. For the three months endedMarch 31, 2017 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in Sunoco LP decreased due to the net impact of the following:

• a decrease of $8 million in gross margin primarily attributable to a $25 million decrease in the gross profit on wholesale motor fuel, offset by an increase in the rental and other gross profit of $8 million due to increased other retail income such as car wash, ATM and lottery income, an increase in the gross profit on retail motor fuel of $5 million due to higher sales price per retail motor fuel gallon, and an increase in the merchandise gross profit of $4 million due to the increase in the number of retail sites.

• an increase in general and administrative expenses of $5 million primarily due to higher advertising costs and salaries and wages compared to the prior period.

• an increase in other operating expenses of $15 million primarily attributable to Sunoco LP’s retail business which has expanded through third-party acquisitions as well as through the construction of new-to-industry sites.

Investment in Lake Charles LNG

	Three Months Ended March 31,
	2017			2016			Change
Revenues	$	49		$	49		$	—
Operating expenses, excluding non-cash compensation expense	(5		)	(4		)	(1		)
Selling, general and administrative, excluding non-cash compensation expense	—			(1		)	1
Segment Adjusted EBITDA	$	44		$	44		$	—

Lake Charles LNG derives all of its revenue from a long-term contract with BG Group plc.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The amount of cash that our subsidiaries distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below. In connection with previous transactions, we have relinquished a portion of incentive distributions to be received, and we may agree to do so in the future, in connection with transactions or otherwise.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP, Sunoco LP and Lake Charles LNG. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its unitholders on a quarterly basis.

We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

ETP

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

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

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

Sunoco LP

Sunoco LP’s ability to satisfy its obligations and pay distributions to its unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of Sunoco LP’s management.

Sunoco LP currently expects to spend approximately $200 million on growth capital and $90 million on maintenance capital for the full year 2017.

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 operating entities 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 acquisitions and other factors.

Operating Activities

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

Three months ended March 31,2017 compared to three months ended March 31,2016. Cash provided by operating activities during 2017 was $893 million as compared to $985 million for 2016. Net income was $290 million and $336 million for 2017 and 2016, respectively. The difference between net income and the net cash provided by operating activities for the three months ended March 31, 2017 and 2016, primarily consisted of non-cash items totaling $623 million and $482 million, respectively, and net changes in operating assets and liabilities of $57 million and $90 million, respectively.

The non-cash activity in 2017 and 2016 consisted primarily of depreciation, depletion and amortization of $661 million and $562 million, respectively, equity in earnings of unconsolidated affiliates of $87 million and $61 million, respectively, inventory valuation adjustments of $12 million and $13 million, respectively, deferred income taxes of $34 million and $46 million, respectively, and unit-based compensation expense of $27 million and $1 million, respectively.

Cash paid for interest, net of interest capitalized, was $491 million and $427 million for the three months ended March 31, 2017 and 2016, respectively.

Capitalized interest was $53 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 growth capital expenditures to fund 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 $203 million as compared to cash used in investing activities $1.94 billion for 2016. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2017 were $1.44 billion. This compares to total capital expenditures (excluding the allowance for equity funds used during construction

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and net of contributions in aid of construction costs) for 2016 of $1.94 billion. During the three months ended March 31, 2017, we had proceeds from transactions of $1.7 billion.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund acquisitions and growth capital expenditures. Distribution increases between the periods were based on increases in distribution rates, increases in the number of common units outstanding at our subsidiaries and increases in the number of our common units outstanding.

Three months ended March 31,2017 compared to three months ended March 31,2016. Cash used in financing activities during 2017 was $1.21 billion as compared to cash provided by financing activities of $1.16 billion for 2016. In 2017, ETP received $826 million in net proceeds from offerings of their common units as compared to $363 million in 2016. In 2016, Sunoco Logistics received $301 million in net proceeds from offerings of their common units. During 2017, we had a consolidated net decrease in our debt level of $809 million as compared to a net increase of $1.33 billion for 2016. In 2017, we paid net proceeds on affiliates notes in the amount of $268 million. We have paid distributions of $251 million and $299 million to our partners in 2017 and in 2016, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $752 million and $658 million in 2017 and 2016, respectively.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	March 31, 2017			December 31, 2016
Parent Company Indebtedness:
ETE Senior Notes due October 2020	$	1,187		$	1,187
ETE Senior Notes due January 2024	1,150			1,150
ETE Senior Notes due June 2027	1,000			1,000
ETE Senior Secured Term Loan, due December 2, 2019	2,200			2,190
ETE Senior Secured Revolving Credit Facility	1,149			875
Subsidiary Indebtedness:
ETP Senior Notes	20,540			19,440
Panhandle Senior Notes	1,085			1,085
Sunoco, Inc. Senior Notes	65			465
Sunoco Logistics Senior Notes	5,350			5,350
Transwestern Senior Notes	657			657
Sunoco LP Senior Notes, Term Loan and lease-related obligation	3,559			3,561
Revolving Credit Facilities:
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
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019	761			1,000
Bakken Term Note	2,500			1,100
PennTex $275 million Revolving Credit Facility due December 2019	157			168
Other Long-Term Debt	30			31
Unamortized premiums and fair value adjustments, net	93			101
Deferred debt issuance costs	(267		)	(257		)
Total	42,975			43,802
Less: Current maturities of long-term debt	392			1,194
Long-term debt and notes payable, less current maturities	$	42,583		$	42,608

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

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⁽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.

Senior Notes and Term Loan

ETE Term Loan Facility

On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLP Merger, ETP , and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLP Merger, ETP, and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.4 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in, immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.

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.

Sunoco LP Term Loan Waiver

Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of March 31, 2017, the balance on the term loan was $1.2 billion.

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Credit Facilities and Commercial Paper

Parent Company Credit Facility

Indebtedness under the Parent Company Credit Facility is secured by all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, but is not guaranteed by any of the Parent Company’s subsidiaries.

On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the Revolver Lenders have committed to provide advances up to an aggregate principal amount of $1.5 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of March 31, 2017, there were $1,149 million outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $351 million.

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.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility. As of March 31, 2017, the Sunoco LP credit facility had $761 million of outstanding borrowings and $21 million in standby letters of credit. The unused availability on the revolver at March 31, 2017 was $718 million.

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, $2.5 billionwas outstanding under this credit facility.

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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 and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2017.

CASH DISTRIBUTIONS

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements.

Following are distributions declared and/or paid by us subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016 (1)	February 7, 2017	February 21, 2017	$	0.2850
March 31, 2017 (1)	May 10, 2017	May 19, 2017	0.2850

⁽¹⁾  Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8, ETE Series A Preferred Units.

Our distributions declared with respect to our Convertible Units during the year ended December 31, 2016 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 21, 2017	$	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100

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

	Three Months Ended March 31,
	2017		2016
Limited Partners	$	250	$	240
General Partner interest	1		1
Total Parent Company distributions	$	251	$	241

Cash Distributions Received by the Parent Company

The Parent Company’s cash available for distributions historically has been primarily generated from its direct and indirect interests in ETP and Sunoco LP. Lake Charles LNG also contributes to the Parent Company’s cash available for distributions.

As the holder of ETP’s IDRs, the Parent Company has historically been entitled to an increasing share of ETP’s total distributions above certain target levels. Following the merger of ETP and Sunoco Logistics in April 2017, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by Post-Merger ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes

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the target levels related to Post-Merger ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of Post-Merger ETP’s general partner interest, Class I units and a portion of the outstanding Post-Merger ETP common units.

	Percentage of Total Distributions to IDRs	Quarterly Distribution Rate Target Amounts
Minimum quarterly distribution	—%	$0.075
First target distribution	—%	$0.075 to $0.0833
Second target distribution	13%	$0.0833 to $0.0958
Third target distribution	35%	$0.0958 to $0.2638
Fourth target distribution	48%	Above $0.2638

The total amount of distributions to the Parent Company from its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is as follows:

	Three Months Ended March 31,
	2017			2016
Distributions from ETP:
Limited Partner interests	$	19		$	3
Class H Units	97			83
General Partner interest	8			8
IDRs	354			331
IDR relinquishments net of Class I Unit distributions	(150		)	(34		)
Total distributions from ETP	328			391
Distributions from Sunoco LP
Limited Partner interests	2			2
IDRs	21			19
Total distributions from Sunoco LP	23			21
Total distributions received from subsidiaries	$	351		$	412

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

	Total Year
2017 (remainder)	$	499
2018	153
2019	128
Each year beyond 2019	33

ETE may agree to relinquish its rights to additional amounts of incentive distributions in future periods. Please see “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016. ETE may agree to relinquish its rights to a portion of its incentive distributions in future periods without the consent of ETE unitholders.

Cash Distributions Paid by Subsidiaries

Certain of our subsidiaries are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

48

Cash Distributions Paid by ETP and Sunoco Logistics

Following the merger of ETP and Sunoco Logistics in April 2017, the Post-Merger ETP partnership agreement contains distribution provisions consistent with those of Sunoco Logistics 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 amount of distributions declared during the periods presented were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):

	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

Cash Distributions Paid by PennTex

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

Cash Distributions Paid by Sunoco LP

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 13, 2017	February 21, 2017	$	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255

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

	Three Months Ended March 31,
	2017		2016
Limited Partners:
Common units held by public	$	44	$	41
Common and subordinated units held by ETP	36		35
Common and subordinated units held by ETE	2		2
General Partner interest and Incentive distributions	21		19
Total distributions declared	$	103	$	97

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 in our Annual Report on Form 10-K 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.

50

	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			—
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(1,827,400	)	3			12		(5,786,627	)	(40		)	35
Refined Products (Bbls) — Futures	(1,492,000	)	(3		)	9		(3,144,000	)	(21		)	18
Corn (Bushels) — Futures	(730,000	)	—			—		1,580,000		—			1
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 and our subsidiaries had $8.62 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $86 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.

51

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

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

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $200 million as of March 31, 2017. For ETP’s $1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $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 President (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of 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, other than those discussed above, over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended March 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 Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

ITEM 1A. RISK FACTORS

The following risk factors should be read in conjunction with our risk factors described in “Part I — Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016.

Risks associated with the pending 7-Eleven Transaction may adversely affect Sunoco LP’s business, financial condition, results of operations and cash flows. There is no assurance when or even if the transaction will be completed.

Risks associated with the pending 7-Eleven Transaction may adversely affect Sunoco LP’s business, financial condition, results of operations and cash flows. Potential risks and uncertainties related to the 7-Eleven Transaction include, among others:

• the possibility that Sunoco LP may not complete the 7-Eleven Transaction in a timely manner, or at all, including due to the failure to receive any necessary governmental or regulatory approvals required to complete the transactions contemplated by the asset purchase agreement;

• the occurrence of any event, change or other circumstance that would give rise to the termination of the 7-Eleven asset purchase agreement;

• the risk that the 7-Eleven Transaction disrupts current plans and operations, results in management distraction and the potential difficulties in maintaining relationships with customers, suppliers and other third parties and employee retention as a result of the announcement and consummation of the 7-Eleven Transaction;

• the outcome of any legal proceedings that may be instituted against us following the announcement of the 7-Eleven Transaction;

• limitations placed on Sunoco LP’s ability to operate its retail business under the 7-Eleven asset purchase agreement;

• the possibility of purchase price adjustments pursuant to the terms of the 7-Eleven asset purchase agreement, which could reduce the cash proceeds ultimately received by Sunoco LP in the 7-Eleven Transaction, even if it is completed; and

• costs, fees, expenses and charges related to the 7-Eleven Transaction.

There can be no assurance that Sunoco LP will be able to satisfy the 7-Eleven Transaction closing conditions or that closing conditions beyond Sunoco LP’s control will be satisfied or waived.

The completion of the 7-Eleven Transaction may result in credit ratings organizations and/or securities analysts taking actions that may adversely affect Sunoco LP’s business, financial condition, results of operations and cash flows, as well as the market price of Sunoco LP’s securities.

In connection with the completion of the 7-Eleven Transaction, ratings agencies may reevaluate Sunoco LP’s credit ratings. A downgrade may increase Sunoco LP’s cost of borrowing, negatively impact Sunoco LP’s ability to raise additional debt capital, negatively impact its ability to successfully compete or negatively impact the willingness of counterparties to deal with Sunoco LP, each of which could have a material adverse effect on its business, financial condition, results of operations and cash flows, as well as the market price of its securities.

Further, the trading market for Sunoco LP’s securities will depend in part on the research and reports that third-party securities analysts publish about Sunoco LP. In connection with the completion of the 7-Eleven Transaction, one or more of these analysts could downgrade Sunoco LP’s securities or issue other negative commentary about Sunoco LP or the industry in which Sunoco LP participates, which could cause the trading price of its securities to decline.

Sunoco LP may not complete the 7-Eleven Transaction if it is unable to satisfy certain closing conditions relating to its senior notes and credit facilities.

The asset purchase agreement for the 7-Eleven Transaction contains provisions that require Sunoco LP, prior to the closing, to either (i) satisfy and discharge the indentures governing its outstanding 6.250% Senior Notes due 2021, 5.500% Senior Notes due

53

2020 and 6.375% Senior Notes due 2023 (collectively, the “Sunoco LP Senior Notes”) pursuant to the terms of the respective indentures or (ii) complete a consent solicitation to the holders of the Sunoco LP Senior Notes pursuant to which the indentures governing the Sunoco LP Senior Notes are to be amended to modify, delete or waive the change of control covenants, merger covenants and other provisions in the indentures with respect to the 7-Eleven Transaction. In addition, Sunoco LP will be required to obtain waivers under its credit facilities to permit the 7-Eleven Transaction. However, it is possible that Sunoco LP will not have sufficient funds, or the ability to raise sufficient funds, to either redeem or repurchase the Sunoco LP Senior Notes or obtain the consent of a majority of the holders of each series of Sunoco LP Senior Notes to amend the indentures, or obtain the consent of a majority of the lenders of each of the credit facilities, and Sunoco LP may be unable to complete the 7-Eleven Transaction as a result.

ITEM 6. EXHIBITS

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

Exhibit Number	Description
1.1	Equity Distribution Agreement, dated as of March 21, 2017, by and among Energy Transfer Equity, L.P., Citigroup Global Markets Inc., Barclays Capital Inc., Credit Agricole Securities (USA) Inc., Deutsche Bank Securities Inc., Fifth Third Securities, Inc., Goldman, Sachs & Co., HSBC Securities (USA) Inc., Jefferies LLC, J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Securities USA Inc., Morgan Stanley & Co. LLC, MUFG Securities Americas Inc., Natixis Securities Americas LLC, RBC Capital Markets, LLC, Scotia Capital (USA) Inc., SMBC Nikko Securities America, Inc., TD Securities (USA) LLC, UBS Securities LLC and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 1.1 of Form 8-K, File No. 1-32740, filed March 21, 2017.)
10.1	Credit Agreement, dated March 24, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed March 24, 2017.)
12.1*	Computation of Ratio of Earnings to Fixed Charges.
31.1*	Certification of President pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of President pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definitions Document
101.LAB*	XBRL Taxonomy Label Linkbase Document
101.PRE*	XBRL Taxonomy Presentation Linkbase Document

*	Filed herewith.
**	Furnished herewith.

54

SIGNATURE

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

		ENERGY TRANSFER EQUITY, L.P.
		By:	LE GP, LLC, its General Partner
Date:	May 4, 2017	By:	/s/ Thomas E. Long
			Thomas E. Long
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)

55

EX-12.1

Exhibit 12.1

ENERGY TRANSFER EQUITY, L.P.

Computation of Ratio of Earnings to Fixed Charges

(in millions, except for ratio amounts)

(Unaudited)

	Three months ended
	March 31, 2017
Fixed Charges:
Interest expense, net	$	486
Capitalized interest	53
Interest charges included in rental expense	5
Total fixed charges	544
Earnings:
Income before income tax expense and noncontrolling interest	325
Less: equity in earnings of unconsolidated affiliates	87
Total earnings	238
Add:
Fixed charges	544
Amortization of capitalized interest	5
Distributed income of equity investees	46
Less:
Interest capitalized	(53		)
Income available for fixed charges	$	780
Ratio of earnings to fixed charges	1.43

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:

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

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. I am 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 my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me 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 my 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 my 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. I have disclosed, based on my 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/ John W. McReynolds

John W. McReynolds

President

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 Equity, L.P.;

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. I am 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 my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me 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 my 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 my 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. I have disclosed, based on my 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

Group 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 Equity, L.P. (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, John W. McReynolds, President, 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/ John W. McReynolds

John W. McReynolds

President

A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer Equity, L.P. 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 Equity, L.P. (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

Group 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 Equity, L.P. and furnished to the Securities and Exchange Commission upon request.

XML

DEI Document - shares	3 Months Ended
	Mar. 31, 2017	Apr. 28, 2017
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,079,185,030

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
ASSETS
Cash and cash equivalents	$ 370	$ 483
Accounts receivable, net	3,485	3,557
Accounts receivable from related companies	72	47
Inventories	2,065	2,291
Derivative assets	9	21
Other current assets	513	586
Total current assets	6,514	6,985
Property, plant and equipment	65,788	63,721
Accumulated depreciation and depletion	(8,821)	(8,283)
Property, Plant and Equipment, Net	56,967	55,438
Advances to and investments in unconsolidated affiliates	3,103	3,040
Other non-current assets, net	826	818
Intangible assets, net	6,837	5,992
Goodwill	6,750	6,738
Total assets	80,997	79,011
LIABILITIES AND EQUITY
Accounts payable	3,363	3,502
Accounts payable to related companies	33	42
Derivative liabilities	126	172
Accrued and other current liabilities	2,304	2,367
Current maturities of long-term debt	392	1,194
Total current liabilities	6,218	7,277
Long-term debt, less current maturities	42,583	42,608
Long-term notes payable – related companies	0	250
Non-current derivative liabilities	72	76
Deferred income taxes	5,130	5,112
Other non-current liabilities	1,237	1,123
Commitments and contingencies
Preferred units of subsidiary	0	33
Redeemable noncontrolling interests	15	15
EQUITY:
General Partner	(3)	(3)
Limited Partners:
Common Unitholders	(1,389)	(1,871)
Series A Convertible Preferred Units	245	180
Total partners’ capital (deficit)	(1,147)	(1,694)
Noncontrolling interest	26,889	24,211
Total equity	25,742	22,517
Total liabilities and equity	$ 80,997	$ 79,011

XML

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	1,546	940
Crude sales	2,347	1,209
Gathering, transportation and other fees	1,065	1,003
Refined product sales	4,155	2,539
Other	1,122	1,166
Total revenues	11,247	7,695
COSTS AND EXPENSES
Cost of products sold	8,991	5,623
Operating expenses	673	641
Depreciation, depletion and amortization	661	562
Selling, general and administrative	197	168
Total costs and expenses	10,522	6,994
OPERATING INCOME	725	701
OTHER INCOME (EXPENSE)
Interest expense, net	(486)	(427)
Equity in earnings of unconsolidated affiliates	87	61
Losses on extinguishments of debt	(25)	0
Gains (losses) on interest rate derivatives	5	(70)
Other, net	19	16
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	325	281
Income tax expense (benefit)	35	(55)
NET INCOME	290	336
Less: Net income attributable to noncontrolling interest	51	24
NET INCOME ATTRIBUTABLE TO PARTNERS	239	312
General Partner’s interest in net income	1	1
Convertible Unitholders’ interest in income	6	0
Limited Partners’ interest in net income	$ 232	$ 311
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$ 0.22	$ 0.30
Diluted	$ 0.21	$ 0.30

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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	$ 290	$ 336
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)
Other comprehensive income (loss), net of tax	0	(14)
Comprehensive income	290	322
Less: Comprehensive income attributable to noncontrolling interest	51	10
Comprehensive income attributable to partners	$ 239	$ 312

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Consolidated Statement Of Equity - 3 months ended Mar. 31, 2017 - USD ($) $ in Millions	Total	General Partner	Common Unitholders	Series A Convertible Preferred Units [Member]	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	$ 2,000	$ 0	$ 42	$ 0	$ 0	$ 1,958
Balance, December 31, 2016 at Dec. 31, 2016	22,517	(3)	(1,871)	180	0	24,211
Distributions to partners	(251)	(1)	(250)	0	0	0
Distributions to noncontrolling interest	(752)	0	0	0	0	(752)
Partners' Capital Account, Convertible Unit Distributions	0	0	(58)	58	0	0
Subsidiary units issued	299	0	(52)	0	0	351
Partners' Capital Account, Sale of Units	568	0	568	0	0	0
Capital contributions received from noncontrolling interest	1,094	0	0	0	0	1,094
Other comprehensive loss, net of tax	0
Other, net	(23)	0		1	0	(24)
Net income	290	1	232	6	0	51
Balance, March 31, 2017 at Mar. 31, 2017	$ 25,742	$ (3)	$ (1,389)	$ 245	$ 0	$ 26,889

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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	$ 290	$ 336
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	661	562
Deferred income taxes	34	(46)
Amortization included in interest expense	5	(3)
Unit-based compensation expense	27	1
(Gains) losses on disposal of assets	6	3
Losses on extinguishments of debt	(25)	0
Inventory valuation adjustments	12	13
Equity in earnings of unconsolidated affiliates	(87)	(61)
Distributions from unconsolidated affiliates	46	84
Distributions On Unvested Unit Awards	(9)	(7)
Other non-cash	(60)	13
Net change in operating assets and liabilities, net of effects of acquisition	(57)	90
Net cash provided by operating activities	893	985
INVESTING ACTIVITIES
Cash received from Bakken Pipeline Transaction	2,000	0
Proceeds from (cash paid for) acquisitions, net of cash received	(330)	(2)
Capital expenditures, excluding allowance for equity funds used during construction	(1,450)	(1,948)
Contributions in aid of construction costs	6	10
Contributions to unconsolidated affiliate	111	31
Distributions from unconsolidated affiliates in excess of cumulative earnings	90	21
Proceeds from the sale of assets	1	10
Change in restricted cash	0	1
Other	(3)	(1)
Net cash used in investing activities	203	(1,942)
FINANCING ACTIVITIES
Proceeds from borrowings	9,000	5,750
Repayments of long-term debt	(9,809)	(4,422)
Repayments of Related Party Debt	(268)	0
Subsidiary units issued for cash	299	664
Proceeds from Issuance of Common Limited Partners Units	568	0
Distributions to partners	(251)	(299)
Debt issuance costs	(53)	(19)
Distributions to noncontrolling interest	(752)	(658)
Payments for Repurchase of Preferred Stock and Preference Stock	(53)	0
Capital contributions received from noncontrolling interest	106	132
Other, net	4	10
Net cash provided by financing activities	(1,209)	1,158
Increase (decrease) in cash and cash equivalents	(113)	201
Cash and cash equivalents, beginning of period	483	606
Cash and cash equivalents, end of period	$ 370	$ 807

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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

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

In April 2017, Energy Transfer Partners, L.P. (“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.

Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P.

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 ETE presented herein include the results of operations of:

• the Parent Company;

• our controlled subsidiaries, ETP and Sunoco LP;

• consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDR interests in ETP and Sunoco LP; and

• our wholly-owned subsidiary, Lake Charles LNG.

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 14 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

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 2017 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.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP or Sunoco LP (excluding transactions with the Parent Company) as capital transactions.

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

3 Months Ended

Mar. 31, 2017

ACQUISITIONS AND DIVESTITURE [Abstract]

Acquisitions

ACQUISITIONS AND DIVESTURES

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. 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.

Prior to the merger of ETP and Sunoco Logistics, ETE owned 18.4 million ETP common units (representing 3.3% of the total outstanding ETP common units), 81 million ETP Class H units and 100 ETP Class I units. In connection with the merger, the ETP Class H units were cancelled, and ETE now owns 27.5 million Post-Merger ETP common units (representing 2.5% of the total outstanding Post-Merger ETP common units) and 100 Post-Merger ETP Class I units. The Post-Merger ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the ETP Class I units.

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 $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.

Sunoco LP Convenience Store Sale

On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for the sale of a portfolio of approximately 1,100 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc. for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”) . The transaction is expected to close in the second half of 2017.

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Cash And Cash Equivalents

3 Months Ended

Mar. 31, 2017

Supplemental Cash Flow Information [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 by uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Non-cash investing activities were as follows:

	Three Months Ended March 31,
	2017			2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	833		$	829
Losses from subsidiary common unit issuances, net	(52		)	(12		)
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988		$	—

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Inventories (Notes)

3 Months Ended

Mar. 31, 2017

Inventory, Net [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	455		540
Other	352		369
Total inventories	$	2,065	$	2,291

ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventories stored in our Bammel storage facility. 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 $44.34 billion and $42.98 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations was $45.05 billion and $43.80 billion, respectively. The fair value of our consolidated debt obligations is Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.

We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP 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 the 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:
Forwards	7			—			7			—
Options — Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	91			91			—			—
Refined Products — Futures	2			2			—			—
Crude – Futures	12			12			—			—
Total commodity derivatives	154			143			11			—
Total assets	$	154		$	143		$	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	(5		)	(5		)	—			—
Crude — Futures	(9		)	(9		)	—			—
Total commodity derivatives	(163		)	(154		)	(9		)	—
Total liabilities	$	(351	)	$	(154	)	$	(197	)	$	—

				Fair Value Measurements at December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX	14			14			—			—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Contracts	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options — Calls	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	233			233			—			—
Refined Products — Futures	2			2			—			—
Crude - Futures	9			9			—			—
Total commodity derivatives	363			356			7			—
Total assets	$	363		$	356		$	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	(23		)	(23		)	—			—
Crude - Futures	(13		)	(13		)	—			—
Total commodity derivatives	(478		)	(470		)	(8		)	—
Total liabilities	$	(672	)	$	(470	)	$	(201	)	$	(1	)

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Net Income per Limited Partner Unit

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Net Income Per Limited Partner Unit

NET INCOME PER LIMITED PARTNER UNIT

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

	Three Months Ended March 31,
	2017		2016
Net Income	$	290	$	336
Less: Income attributable to noncontrolling interest	51		24
Net Income, net of noncontrolling interest	239		312
Less: General Partner’s interest in income	1		1
Less: Convertible Unitholders’ interest in income	6		—
Income available to Limited Partners	$	232	$	311
Basic Income per Limited Partner Unit:
Weighted average limited partner units	1,075.2		1,044.8
Basic income per Limited Partner unit	$	0.22	$	0.30
Diluted Income per Limited Partner Unit:
Income available to Limited Partners	$	232	$	311
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	6		—
Diluted income available to Limited Partners	$	238	$	311
Weighted average limited partner units	1,075.2		1,044.8
Dilutive effect of unconverted unit awards and Convertible Units	63.8		—
Diluted weighted average limited partner units	1,139.0		1,044.8
Diluted income per Limited Partner unit	$	0.21	$	0.30

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Debt Obligations

3 Months Ended

Mar. 31, 2017

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS

Parent Company Indebtedness

The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.

ETE Term Loan Facility

On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLP Merger, ETP , and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLP Merger, ETP, and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.4 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in, immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.

Revolving Credit Facility

On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the Revolver Lenders have committed to provide advances up to an aggregate principal amount of $1.5 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of March 31, 2017, there were $1.15 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $351 million.

Subsidiary Indebtedness

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.

Sunoco LP Term Loan

Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of March 31, 2017, the balance on the term loan was $1.2 billion.

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.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility. As of March 31, 2017, the Sunoco LP credit facility had $761 million of outstanding borrowings and $21 million in standby letters of credit. The unused availability on the revolver at March 31, 2017 was $718 million.

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 and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2017.

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Redeemable Preferred Units (Notes)

3 Months Ended

Mar. 31, 2017

Redeemable Preferred Units [Abstract]

Preferred Units [Text Block]

REDEEMABLE 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

ETE

The changes in ETE common units and Convertible Units during the three months ended March 31,2017 were as follows:

	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2016	329.3	1,046.9
Issuance of common units	—	32.2
Outstanding at March 31, 2017	329.3	1,079.1

ETE Equity Distribution Agreement

In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the three months endedMarch 31, 2017.

Series A Convertible Preferred Units

As of March 31, 2017, The Partnership had 329.3 million Series A Convertible Preferred Units outstanding with a carrying value of $245 million.

ETE January 2017 Private Placement and ETP Unit Purchase

In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 15.8 million newly issued ETP common units for approximately $568 million.

Repurchase Program

During the three months endedMarch 31, 2017, ETE did not repurchase any ETE common units under its current buyback program. As of March 31, 2017, $936 million remained available to repurchase under the current program.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the three months ended March 31, 2017, we recognized decreases in partners’ capital of $52 million.

ETP Common Unit Transactions

During the three months ended March 31,2017, ETP 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 ETP’s distribution reinvestment plan. In connection with the merger of ETP and Sunoco Logistics in April 2017, the distribution reinvestment plan was terminated.

Sunoco Logistics Common Unit Transactions

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

Sunoco LP Common Unit Transactions

During the three months ended March 31,2017, Sunoco LP received net proceeds of $33 million from the issuance of 1.3 million Sunoco LP common units pursuant to its equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. As of March 31, 2017, $295 million of Sunoco LP’s common units remained available to be issued under the equity distribution agreement.

Sunoco LP Series A Preferred Units

On March 30, 2017, the Partnership purchased Sunoco LP’s 12.0 million series A preferred units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.

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.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016 (1)	February 7, 2017	February 21, 2017	$	0.2850
March 31, 2017 (1)	May 10, 2017	May 19, 2017	0.2850

⁽¹⁾  Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit.

Our distributions declared with respect to our Convertible Units subsequent to December 31, 2016 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 21, 2017	$	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100

ETP and Sunoco Logistics Quarterly Distributions of Available Cash

Following the merger of ETP and Sunoco Logistics in April 2017, the Post-Merger ETP partnership agreement contains distribution provisions consistent with those of Sunoco Logistics 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.

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

	Total Year
2017 (remainder)	$	499
2018	153
2019	128
Each year beyond 2019	33

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

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 13, 2017	February 21, 2017	$	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255

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 loss related to pensions and other postretirement benefits	5			7
Investments in unconsolidated affiliates, net	4			4
Subtotal	8			8
Amounts attributable to noncontrolling interest	(8		)	(8		)
Total AOCI, net of tax	$	—		$	—

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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.

NGL Pipeline Regulation

ETP has interests in NGL pipelines located in Texas and New Mexico. ETP 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 ETP’s 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 ETP’s 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(1)	$	54		$	51
Less: Sublease rental income	(6		)	(7		)
Rental expense, net	$	48		$	44

⁽¹⁾  Includes contingent rentals totaling $5 million and $16 million for the three months ended March 31,2017 and 2016, respectively.

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

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 claim related to its 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.

Litigation Filed By or Against WMB

On April 6, 2016, WMB filed a complaint against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG. WMB alleged that Defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates (the “Merger Agreement”) by issuing ETE’s Series A Convertible Preferred Units. According to WMB, the issuance of Convertible Units (the “Issuance”) violates various contractual restrictions on ETE’s actions between the execution and closing of the merger. WMB sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware WMB Litigation. The counterclaim asserts in general that WMB materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow WMB’s independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing the Texas WMB Litigation against Mr. Warren in the District Court of Dallas County, Texas.

On May 13, 2016, WMB filed a second lawsuit in the Delaware Court of Chancery against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (the “Second Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG. In general, WMB alleged that the defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion under Section 721 of the Tax Code (“721 Opinion”), a condition precedent to the closing of the merger, and (b) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. WMB asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions. WMB sought to expedite the second lawsuit, and ETE agreed to expedite both Delaware actions.

ETE also filed an answer and counterclaim in the Second Delaware WMB Litigation. In addition to the counterclaims previously asserted, ETE asserted that WMB materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the WMB board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger necessary to prevent the Form S-4 from being materially misleading, (c) failing to facilitate the financing of the merger, (d) failing to be reasonable with respect to its withholding of its consent to ETE’s offering of Series A Convertible Preferred Units, and (e) failing to use its reasonable best efforts to consummate the merger. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’s requests for injunctive relief. WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.

Williams filed an amended complaint on September 16, 2016. In the amended complaint, Williams abandons its request for injunctive relief, including its request that the Court order the ETE Defendants to consummate the merger. Instead, Williams seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement.

The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016. In the amended counterclaim, the ETE Defendants seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.

On January 11, 2017, the Delaware Supreme Court held oral arguments on Williams’ appeal of the June 2016 trial. The Delaware Supreme Court affirmed the Court of Chancery on March 23, 2017 and denied Williams’ motion for reargument on April 5, 2017.

The parties are currently engaging in discovery in connection with their amended claims and counterclaims.

Unitholder Litigation Relating to the Issuance

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware. Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.

The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of Convertible Units.

The parties engaged in discovery, and Plaintiffs’ filed a consolidated amended complaint on August 29, 2016. In addition to the injunctive relief described above, Plaintiffs seek class-wide damages allegedly resulting from the Issuance.

On September 28, 2016, Defendants and Plaintiffs filed cross-motions for partial summary judgment. The Court held a hearing on the parties’ motions on November 9, 2016. On February 28, 2017, the Court denied both motions for partial summary judgment. The parties are continuing to engage in discovery.

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, 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.  Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products.  As a result, there can be no assurance that significant costs and liabilities will not be incurred.  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 remedial obligations, the issuance of injunctions 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 ofMarch 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	$	32	$	31
Non-current	321		318
Total environmental liabilities	$	353	$	349

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, the Partnership recorded $4 million and $8 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 its 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]

Derivative 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, our subsidiaries 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 futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment. 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 and Crude (Bbls) — Forwards/Swaps	(1,827,400	)	2017	(5,786,627	)	2017
Refined Products (Bbls) — Futures	(1,492,000	)	2017	(3,144,000	)	2017
Corn (Bushels) — Futures	(730,000	)	2017	1,580,000		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 anticipated debt issuances.

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

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

Credit Risk

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

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

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

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

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	15		25		(16		)	(58		)
Interest rate derivatives	—		—		(188		)	(193		)
Embedded derivatives in the ETP Preferred Units	—		—		—			(1		)
	154		363		(349		)	(668		)
Total derivatives	$	154	$	363	$	(351	)	$	(672	)

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)	15			25			(16		)	(58		)
Broker cleared derivative contracts	Other current assets	139			338			(147		)	(420		)
Total gross derivatives		154			363			(351		)	(672		)
Less 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		$	15		$	21		$	(212	)	$	(330	)

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	2		8
Interest rate derivatives	Gains (losses) on interest rate derivatives	5		(70		)
Embedded derivatives	Other, net	1		—
Total		$	19	$	(71	)

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Related Party Transactions

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

ETP previously had agreements with the Parent Company to provide services on its behalf and the behalf of other subsidiaries of the Parent Company, which included the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. These agreements have subsequently expired.

In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

In addition, ETE recorded sales with affiliates of $50 million and $81 million during the three months endedMarch 31, 2017 and 2016, respectively.

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Reportable Segments

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Reportable Segments

REPORTABLE SEGMENTS

Our financial statements reflect the following reportable business segments:

• Investment in ETP, including the consolidated operations of ETP;

• Investment in Sunoco LP, including the consolidated operations of Sunoco LP;

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and

• Corporate and Other, including the following:

• activities of the Parent Company; and

• the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

The Investment in Sunoco LP segment reflects the results of Sunoco LP and the legacy Sunoco, Inc. retail business for the periods presented.

Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

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

The following tables present financial information by segment:

	Three Months Ended March 31,
	2017			2016
Segment Adjusted EBITDA:
Investment in ETP	$	1,414		$	1,412
Investment in Sunoco LP	155			159
Investment in Lake Charles LNG	44			44
Corporate and Other	(13		)	(37		)
Adjustments and Eliminations	(54		)	(57		)
Total	1,546			1,521
Depreciation, depletion and amortization	(661		)	(562		)
Interest expense, net	(486		)	(427		)
Unrealized gains (losses) on interest rate derivatives	5			(70		)
Non-cash unit-based compensation expense	(27		)	(1		)
Unrealized gains (losses) on commodity risk management activities	69			(60		)
Losses on extinguishments of debt	(25		)	—
Inventory valuation adjustments	(12		)	(13		)
Equity in earnings of unconsolidated affiliates	87			61
Adjusted EBITDA related to unconsolidated affiliates	(185		)	(162		)
Other, net	14			(6		)
Income before income tax expense (benefit)	$	325		$	281

	March 31, 2017			December 31, 2016
Assets:
Investment in ETP	$	72,437		$	70,191
Investment in Sunoco LP	8,454			8,701
Investment in Lake Charles LNG	1,540			1,508
Corporate and Other	660			711
Adjustments and Eliminations	(2,094		)	(2,100		)
Total assets	$	80,997		$	79,011

	Three Months Ended March 31,
	2017			2016
Revenues:
Investment in ETP:
Revenues from external customers	$	6,807		$	4,434
Intersegment revenues	88			47
	6,895			4,481
Investment in Sunoco LP:
Revenues from external customers	4,391			3,212
Intersegment revenues	3			3
	4,394			3,215
Investment in Lake Charles LNG:
Revenues from external customers	49			49
Adjustments and Eliminations	(91		)	(50		)
Total revenues	$	11,247		$	7,695

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP and Lake Charles LNG.

Investment in ETP

	Three Months Ended March 31,
	2017		2016
Intrastate Transportation and Storage	$	768	$	446
Interstate Transportation and Storage	231		254
Midstream	565		527
Liquids Transportation and Services	1,508		829
Investment in Sunoco Logistics	3,185		1,729
All Other	638		696
Total revenues	6,895		4,481
Less: Intersegment revenues	88		47
Revenues from external customers	$	6,807	$	4,434

Investment in Sunoco LP

	Three Months Ended March 31,
	2017		2016
Retail operations	$	2,098	$	1,675
Wholesale operations	2,296		1,540
Total revenues	4,394		3,215
Less: Intersegment revenues	3		3
Revenues from external customers	$	4,391	$	3,212

Investment in Lake Charles LNG

Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling.

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Supplemental Financial Statement Information

3 Months Ended

Mar. 31, 2017

Supplemental Financial Statement Information

Supplemental Financial Statement Information

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

(unaudited)

	March 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	3		$	2
Accounts receivable, net	2			—
Accounts receivable from related companies	57			55
Total current assets	62			57
Property, plant and equipment, net	35			36
Advances to and investments in unconsolidated affiliates	5,940			5,088
Intangible assets, net	—			1
Goodwill	9			9
Other non-current assets, net	19			10
Total assets	$	6,065		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	1
Accounts payable to related companies	3			22
Interest payable	80			66
Accrued and other current liabilities	3			3
Total current liabilities	86			92
Long-term debt, less current maturities	6,639			6,358
Long-term notes payable – related companies	485			443
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ capital:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,389		)	(1,871		)
Series A Convertible Preferred Units	245			180
Total partners’ capital (deficit)	(1,147		)	(1,694		)
Total liabilities and equity	$	6,065		$	5,201

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2017			2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(13	)	$	(37	)
OTHER INCOME (EXPENSE):
Interest expense, net	(83		)	(81		)
Equity in earnings of unconsolidated affiliates	361			430
Losses on extinguishments of debt	(25		)	—
Other, net	(1		)	—
NET INCOME	239			312
General Partner’s interest in net income	1			1
Convertible Unitholders’ interest in income	6			—
Limited Partners’ interest in net income	$	232		$	311

⁽¹⁾  Includes management fees paid by ETE to ETP, which management fees will no longer be paid subsequent to March 31, 2017.

STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2017			2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	251		$	223
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(860		)	(65		)
Capital expenditures	—			(7		)
Net cash used in investing activities	(860		)	(72		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,017			105
Principal payments on debt	(1,733		)	—
Proceeds from affiliate	43			50
Distributions to partners	(251		)	(299		)
Units issued for cash	568			—
Debt issuance costs	(34		)	—
Net cash provided by (used in) financing activities	610			(144		)
INCREASE IN CASH AND CASH EQUIVALENTS	1			7
CASH AND CASH EQUIVALENTS, beginning of period	2			1
CASH AND CASH EQUIVALENTS, end of period	$	3		$	8

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Operations And Organization Accounting policy (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Consolidation, Subsidiary Stock Issuances, Policy [Policy Text Block]

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP or Sunoco LP (excluding transactions with the Parent Company) as capital transactions.

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

Supplemental Cash Flow Information [Abstract]

Schedule Of Non-Cash Investing and Non-Cash Financing Activities

Non-cash investing activities were as follows:

	Three Months Ended March 31,
	2017			2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	833		$	829
Losses from subsidiary common unit issuances, net	(52		)	(12		)
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, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:

	March 31, 2017		December 31, 2016
Natural gas and NGLs	$	474	$	699
Crude oil	784		683
Refined products	455		540
Other	352		369
Total inventories	$	2,065	$	2,291

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Measurements [Abstract]

Fair Value Of Financial Assets And Liabilities Measured 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:
Forwards	7			—			7			—
Options — Calls	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	91			91			—			—
Refined Products — Futures	2			2			—			—
Crude – Futures	12			12			—			—
Total commodity derivatives	154			143			11			—
Total assets	$	154		$	143		$	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	(5		)	(5		)	—			—
Crude — Futures	(9		)	(9		)	—			—
Total commodity derivatives	(163		)	(154		)	(9		)	—
Total liabilities	$	(351	)	$	(154	)	$	(197	)	$	—

				Fair Value Measurements at December 31, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX	14			14			—			—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	96			96			—			—
Forward Physical Contracts	1			—			1			—
Power:
Forwards	4			—			4			—
Futures	1			1			—			—
Options — Calls	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	233			233			—			—
Refined Products — Futures	2			2			—			—
Crude - Futures	9			9			—			—
Total commodity derivatives	363			356			7			—
Total assets	$	363		$	356		$	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	(23		)	(23		)	—			—
Crude - Futures	(13		)	(13		)	—			—
Total commodity derivatives	(478		)	(470		)	(8		)	—
Total liabilities	$	(672	)	$	(470	)	$	(201	)	$	(1	)

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Net Income per Limited Partner Unit (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Reconciliation Of Net Income And Weighted Average Units

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

	Three Months Ended March 31,
	2017		2016
Net Income	$	290	$	336
Less: Income attributable to noncontrolling interest	51		24
Net Income, net of noncontrolling interest	239		312
Less: General Partner’s interest in income	1		1
Less: Convertible Unitholders’ interest in income	6		—
Income available to Limited Partners	$	232	$	311
Basic Income per Limited Partner Unit:
Weighted average limited partner units	1,075.2		1,044.8
Basic income per Limited Partner unit	$	0.22	$	0.30
Diluted Income per Limited Partner Unit:
Income available to Limited Partners	$	232	$	311
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	6		—
Diluted income available to Limited Partners	$	238	$	311
Weighted average limited partner units	1,075.2		1,044.8
Dilutive effect of unconverted unit awards and Convertible Units	63.8		—
Diluted weighted average limited partner units	1,139.0		1,044.8
Diluted income per Limited Partner unit	$	0.21	$	0.30

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Equity (Tables)

3 Months Ended

Mar. 31, 2017

Change In ETE Common Units

The changes in ETE common units and Convertible Units during the three months ended March 31,2017 were as follows:

	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2016	329.3	1,046.9
Issuance of common units	—	32.2
Outstanding at March 31, 2017	329.3	1,079.1

Schedule of Net IDR Subsidies [Table Text Block]

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

	Total Year
2017 (remainder)	$	499
2018	153
2019	128
Each year beyond 2019	33

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 loss related to pensions and other postretirement benefits	5			7
Investments in unconsolidated affiliates, net	4			4
Subtotal	8			8
Amounts attributable to noncontrolling interest	(8		)	(8		)
Total AOCI, net of tax	$	—		$	—

Parent Company [Member]

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

Following are distributions declared and/or paid by us subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016 (1)	February 7, 2017	February 21, 2017	$	0.2850
March 31, 2017 (1)	May 10, 2017	May 19, 2017	0.2850

⁽¹⁾  Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit.

PennTex [Member]

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

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

Sunoco LP [Member]

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

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2016:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 13, 2017	February 21, 2017	$	0.8255
March 31, 2017	May 9, 2017	May 16, 2017	0.8255

Convertible Units [Member]

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

Our distributions declared with respect to our Convertible Units subsequent to December 31, 2016 were as follows:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2016	February 7, 2017	February 21, 2017	$	0.1100
March 31, 2017	May 10, 2017	May 19, 2017	0.1100

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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(1)	$	54		$	51
Less: Sublease rental income	(6		)	(7		)
Rental expense, net	$	48		$	44

⁽¹⁾  Includes contingent rentals totaling

Environmental Exit Costs by Cost

	March 31, 2017		December 31, 2016
Current	$	32	$	31
Non-current	321		318
Total environmental liabilities	$	353	$	349

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Derivative Assets And Liabilities (Tables)

3 Months Ended

Mar. 31, 2017

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 and Crude (Bbls) — Forwards/Swaps	(1,827,400	)	2017	(5,786,627	)	2017
Refined Products (Bbls) — Futures	(1,492,000	)	2017	(3,144,000	)	2017
Corn (Bushels) — Futures	(730,000	)	2017	1,580,000		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:

		Notional Amount Outstanding
Term	Type(1)	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 a term 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	15		25		(16		)	(58		)
Interest rate derivatives	—		—		(188		)	(193		)
Embedded derivatives in the ETP Preferred Units	—		—		—			(1		)
	154		363		(349		)	(668		)
Total derivatives	$	154	$	363	$	(351	)	$	(672	)

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)	15			25			(16		)	(58		)
Broker cleared derivative contracts	Other current assets	139			338			(147		)	(420		)
Total gross derivatives		154			363			(351		)	(672		)
Less 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		$	15		$	21		$	(212	)	$	(330	)

Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives

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	)

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	2		8
Interest rate derivatives	Gains (losses) on interest rate derivatives	5		(70		)
Embedded derivatives	Other, net	1		—
Total		$	19	$	(71	)

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Reportable Segments (Tables)

3 Months Ended

Mar. 31, 2017

Operating Segments [Member]

Financial Information By Segment

	Three Months Ended March 31,
	2017			2016
Segment Adjusted EBITDA:
Investment in ETP	$	1,414		$	1,412
Investment in Sunoco LP	155			159
Investment in Lake Charles LNG	44			44
Corporate and Other	(13		)	(37		)
Adjustments and Eliminations	(54		)	(57		)
Total	1,546			1,521
Depreciation, depletion and amortization	(661		)	(562		)
Interest expense, net	(486		)	(427		)
Unrealized gains (losses) on interest rate derivatives	5			(70		)
Non-cash unit-based compensation expense	(27		)	(1		)
Unrealized gains (losses) on commodity risk management activities	69			(60		)
Losses on extinguishments of debt	(25		)	—
Inventory valuation adjustments	(12		)	(13		)
Equity in earnings of unconsolidated affiliates	87			61
Adjusted EBITDA related to unconsolidated affiliates	(185		)	(162		)
Other, net	14			(6		)
Income before income tax expense (benefit)	$	325		$	281

Assets Segments [Member]

Financial Information By Segment

	March 31, 2017			December 31, 2016
Assets:
Investment in ETP	$	72,437		$	70,191
Investment in Sunoco LP	8,454			8,701
Investment in Lake Charles LNG	1,540			1,508
Corporate and Other	660			711
Adjustments and Eliminations	(2,094		)	(2,100		)
Total assets	$	80,997		$	79,011

Sales Revenue, Segment [Member]

Financial Information By Segment

	Three Months Ended March 31,
	2017			2016
Revenues:
Investment in ETP:
Revenues from external customers	$	6,807		$	4,434
Intersegment revenues	88			47
	6,895			4,481
Investment in Sunoco LP:
Revenues from external customers	4,391			3,212
Intersegment revenues	3			3
	4,394			3,215
Investment in Lake Charles LNG:
Revenues from external customers	49			49
Adjustments and Eliminations	(91		)	(50		)
Total revenues	$	11,247		$	7,695

Investment In ETP [Member]

Revenue from External Customers by Products and Services [Table Text Block]

Investment in ETP

	Three Months Ended March 31,
	2017		2016
Intrastate Transportation and Storage	$	768	$	446
Interstate Transportation and Storage	231		254
Midstream	565		527
Liquids Transportation and Services	1,508		829
Investment in Sunoco Logistics	3,185		1,729
All Other	638		696
Total revenues	6,895		4,481
Less: Intersegment revenues	88		47
Revenues from external customers	$	6,807	$	4,434

Investment In Sunoco LP [Member]

Revenue from External Customers by Products and Services [Table Text Block]

Investment in Sunoco LP

	Three Months Ended March 31,
	2017		2016
Retail operations	$	2,098	$	1,675
Wholesale operations	2,296		1,540
Total revenues	4,394		3,215
Less: Intersegment revenues	3		3
Revenues from external customers	$	4,391	$	3,212

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Supplemental Financial Statement Information (Tables) - Parent Company [Member]

3 Months Ended

Mar. 31, 2017

Schedule Of Balance Sheets

BALANCE SHEETS

(unaudited)

	March 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	3		$	2
Accounts receivable, net	2			—
Accounts receivable from related companies	57			55
Total current assets	62			57
Property, plant and equipment, net	35			36
Advances to and investments in unconsolidated affiliates	5,940			5,088
Intangible assets, net	—			1
Goodwill	9			9
Other non-current assets, net	19			10
Total assets	$	6,065		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	1
Accounts payable to related companies	3			22
Interest payable	80			66
Accrued and other current liabilities	3			3
Total current liabilities	86			92
Long-term debt, less current maturities	6,639			6,358
Long-term notes payable – related companies	485			443
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ capital:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,389		)	(1,871		)
Series A Convertible Preferred Units	245			180
Total partners’ capital (deficit)	(1,147		)	(1,694		)
Total liabilities and equity	$	6,065		$	5,201

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2017			2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(13	)	$	(37	)
OTHER INCOME (EXPENSE):
Interest expense, net	(83		)	(81		)
Equity in earnings of unconsolidated affiliates	361			430
Losses on extinguishments of debt	(25		)	—
Other, net	(1		)	—
NET INCOME	239			312
General Partner’s interest in net income	1			1
Convertible Unitholders’ interest in income	6			—
Limited Partners’ interest in net income	$	232		$	311

⁽¹⁾  Includes management fees paid by ETE to ETP, which management fees will no longer be paid subsequent to March 31, 2017.

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2017			2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	251		$	223
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(860		)	(65		)
Capital expenditures	—			(7		)
Net cash used in investing activities	(860		)	(72		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,017			105
Principal payments on debt	(1,733		)	—
Proceeds from affiliate	43			50
Distributions to partners	(251		)	(299		)
Units issued for cash	568			—
Debt issuance costs	(34		)	—
Net cash provided by (used in) financing activities	610			(144		)
INCREASE IN CASH AND CASH EQUIVALENTS	1			7
CASH AND CASH EQUIVALENTS, beginning of period	2			1
CASH AND CASH EQUIVALENTS, end of period	$	3		$	8

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Acquisitions Narrative (Details) shares in Millions, $ in Millions	1 Months Ended			3 Months Ended
	Apr. 30, 2017 USD ($) shares	Mar. 31, 2017 shares	Feb. 28, 2017 USD ($)	Mar. 31, 2017 USD ($) shares	May 01, 2017 shares	Feb. 01, 2017
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross | $			$ 2,000
ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		3.30%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		18.4		18.4
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired						49.00%
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			40.00%
Sunoco Logistics [Member] | Permian Express Partners LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			85.00%
ETP [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			60.00%
Dakota Access and ETCOC [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			25.00%
Dakota Access and ETCOC [Member] | Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			75.00%
Bakken Pipeline [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			25.00%
Bakken Pipeline [Member] | ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			38.25%
Bakken Pipeline [Member] | MarEn Bakken Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			36.75%
Class H Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		81.0		81.0
Class I Units [Member] | ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.		0.0		0.0
Subsequent Event [Member] | Pending SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5
Sale of Stock, Number of Shares Issued in Transaction	845.0
Subsequent Event [Member] | 7-Eleven Transaction [Member]
Number of Stores	1,100
Payments to Acquire Businesses, Gross | $	$ 3,300
Subsequent Event [Member] | Post-Merger ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	2.50%
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.					27.5
Subsequent Event [Member] | Class I Units [Member] | Post-Merger ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.					0.0
Customer Relationships [Member] | Sunoco Logistics [Member]
Increase (Decrease) in Intangible Assets, Current | $				$ 547

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Cash And Cash Equivalents Non-Cash Activities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 833	$ 829
Losses from subsidiary common unit issuances, net	(52)	(12)
Non-Cash Financing [Abstract]
Capital Contributions from Noncontrolling Interest	$ 988	$ 0

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Inventories Table - Inventory Balances (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Inventory, Net [Abstract]
Natural gas and NGLs	$ 474	$ 699
Crude oil	784	683
Refined products	455	540
Other	352	369
Total inventories	$ 2,065	$ 2,291

XML

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Fair Value Measurements [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0
Debt obligations, fair value	44,340	$ 45,050
Long-term Debt	$ 42,980	$ 43,800

XML

Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Liabilities, Fair Value Disclosure, Recurring		$ (672)
Level 1
Liabilities, Fair Value Disclosure, Recurring		(470)
Level 2
Liabilities, Fair Value Disclosure, Recurring		(201)
Level 3
Liabilities, Fair Value Disclosure, Recurring		(1)
Commodity Derivatives - Power [Member] | Call Option [Member]
Price Risk Derivative Assets, at Fair Value		1
Commodity Derivatives - Power [Member] | Level 1 | Call Option [Member]
Price Risk Derivative Assets, at Fair Value		1
Commodity Derivatives - Power [Member] | Level 2 | Call Option [Member]
Price Risk Derivative Assets, at Fair Value		0
Commodity Derivatives - Power [Member] | Level 3 | Call Option [Member]
Price Risk Derivative Assets, at Fair Value		0
Fair Value, Measurements, Recurring [Member]
Price Risk Derivative Assets, at Fair Value	$ 154	363
Assets, Fair Value Disclosure	154	363
Interest Rate Derivative Liabilities, at Fair Value	(188)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	(163)	(478)
Liabilities, Fair Value Disclosure, Recurring	(351)
Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	143	356
Assets, Fair Value Disclosure	143	356
Interest Rate Derivative Liabilities, at Fair Value	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(154)	(470)
Liabilities, Fair Value Disclosure, Recurring	(154)
Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	11	7
Assets, Fair Value Disclosure	11	7
Interest Rate Derivative Liabilities, at Fair Value	(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)
Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value	0	0
Assets, Fair Value Disclosure	0	0
Interest Rate Derivative Liabilities, at Fair Value	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
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	7	14
Price Risk Derivative Liabilities, at Fair Value	(10)	(11)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value	(1)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	30	96
Price Risk Derivative Liabilities, at Fair Value	(42)	(149)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	4	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	7	14
Price Risk Derivative Liabilities, at Fair Value	(10)	(11)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	30	96
Price Risk Derivative Liabilities, at Fair Value	(42)	(149)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value		2
Price Risk Derivative Liabilities, at Fair Value	(1)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	4	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	2	2
Price Risk Derivative Liabilities, at Fair Value	(5)	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value	2	2
Price Risk Derivative Liabilities, at Fair Value	(5)	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	12	9
Price Risk Derivative Liabilities, at Fair Value	(9)	(13)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value	12	9
Price Risk Derivative Liabilities, at Fair Value	(9)	(13)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 2 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 3 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	7	4
Price Risk Derivative Liabilities, at Fair Value	(8)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Call Option [Member]
Price Risk Derivative Assets, at Fair Value	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 | Call Option [Member]
Price Risk Derivative Assets, at Fair Value	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value		1
Price Risk Derivative Liabilities, at Fair Value		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	7	4
Price Risk Derivative Liabilities, at Fair Value	(8)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 | Call Option [Member]
Price Risk Derivative Assets, at Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 | Future [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 | Call Option [Member]
Price Risk Derivative Assets, at Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 | Future [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	91	233
Price Risk Derivative Liabilities, at Fair Value	(88)	(273)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	91	233
Price Risk Derivative Liabilities, at Fair Value	(88)	(273)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	$ 0

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Net Income per Limited Partner Unit Table - Income Reconciliation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Net Income	$ 290	$ 336
Less: Income attributable to noncontrolling interest	51	24
Net Income, net of noncontrolling interest	239	312
Less: General Partner’s interest in income	1	1
Less: Convertible Unitholders’ interest in income	6	0
Income available to Limited Partners	$ 232	$ 311
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,075.2	1,044.8
Basic income per Limited Partner unit	$ 0.22	$ 0.30
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	$ (6)	$ 0
Diluted income available to Limited Partners	$ 238	$ 311
Dilutive effect of unconverted unit awards and Convertible Units	63.8	0.0
Diluted weighted average limited partner units	1,139.0	1,044.8
Diluted income per Limited Partner unit	$ 0.21	$ 0.30

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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	Apr. 30, 2015
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 9,809	$ 4,422
Proceeds from Issuance of Long-term Debt	$ 1,480	9,000	5,750
Parent Company [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		1,733	0
Proceeds from Issuance of Long-term Debt		2,017	$ 105
ETE Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		1,500
Line Of Credit Facility, Additional Borrowing Capacity Subject To Lender Approval		500
Letters Of Credit Availablity		150
ETE Senior Secured Revolving Credit Facilities [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding		1,150
Line of Credit Facility, Remaining Borrowing Capacity		351
ETP Revolving Credit Facility, due October 2017 [Member] | ETP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		3,750
Line of Credit Facility, Amount Outstanding		389
Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member] | Sunoco Logistics [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		2,500
Line of Credit Facility, Amount Outstanding		740
Commercial Paper		128
Line of Credit Facility, Maximum Borrowing Capacity		3,250
Bakken Term Note [Member] | Bakken Pipeline [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		2,500
Sunoco LP $1.5 Billion Revolving Credit Facility Due September 2019 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		1,500			$ 1,250
Line of Credit Facility, Amount Outstanding		761
Letters of Credit Outstanding, Amount		21
Line of Credit Facility, Remaining Borrowing Capacity		718
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Secured Debt		$ 2,200
Debt Instrument, Covenant Description		Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLP Merger, ETP , and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLP Merger, ETP, and (ii) upon and after the consummation of the MLP Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Debt Instrument, Collateral		Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.4 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in, immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics.
5.75% Senior Notes, due 2017 [Member] | Sunoco [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	400
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding		$ 2,500
PennTex $275 million Revolving Credit Facility due December 2019 [Member] | PennTex [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		275
Line of Credit Facility, Amount Outstanding		157
Line of Credit Facility, Maximum Borrowing Capacity		400
Sunoco Merger [Member]
Debt Instrument [Line Items]
Senior Notes		65
4.20% Senior Notes due April 2027 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 600
Debt Instrument, Interest Rate, Stated Percentage	4.20%
5.30% Senior Notes due April 2047 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 900
Debt Instrument, Interest Rate, Stated Percentage	5.30%
Term loan due 2019 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		2,035
Line of Credit Facility, Amount Outstanding		$ 1,200
Sunoco Logistics $1.0 billion 364-day Credit Facility due December 2017 [Member] | Sunoco Logistics [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 1,000
Line of Credit Facility, Amount Outstanding				$ 630
Letter of Credit [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.75%
Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Minimum [Member] | Letter of Credit [Member] | ETE Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Minimum [Member] | Base Rate Loans [Member] | ETE Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
Maximum [Member] | Letter of Credit [Member] | ETE Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
Maximum [Member] | Base Rate Loans [Member] | ETE Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%

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Redeemable 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

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Equity Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		1 Months Ended				3 Months Ended				9 Months Ended	12 Months Ended
		Apr. 30, 2017	Mar. 31, 2017	Feb. 28, 2017	Jan. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Feb. 01, 2017
Issuance of common units						32.2
Limited Partners' Capital Account, Units Outstanding			1,079.1			1,079.1	1,046.9
Series A Convertible Preferred Units			$ 245			$ 245	$ 180
Losses from subsidiary common unit issuances, net						(52)		$ (12)
Stock Repurchase Program, Remaining Authorized Repurchase Amount			936			936
Subsidiary units issued						299
Preferred Units, Preferred Partners' Capital Accounts			25,742			25,742	$ 22,517
Noncontrolling Interest, Increase from Sale of Parent Equity Interest						$ 2,000
Partners' Capital Account, Units, Sold in Private Placement					32.2
Proceeds from Issuance of Private Placement					$ 580
Parent Company [Member]
Payment Date						May 19, 2017	Feb. 21, 2017
Series A Convertible Preferred Units			$ 245			$ 245	$ 180
Rate	[1]					$ 0.2850	$ 0.2850
Record Date						May 10, 2017	Feb. 07, 2017
Post-Merger ETP [Member]
Payment Date						May 15, 2017
Rate						$ 0.5350
Record Date						May 10, 2017
ETP [Member]
Stock Issued During Period, Value, Dividend Reinvestment Plan						$ 71
Rate							$ 1.0550
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			3.30%
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement						$ 194
Partners' Capital Account, Units, Sold in Private Placement					15.8
Proceeds from Issuance of Private Placement					$ 568
Sunoco Logistics [Member]
Rate							$ 0.52
PennTex [Member]
Payment Date						May 12, 2017	Feb. 14, 2017
Rate						$ 0.2950	$ 0.2950
Record Date						May 05, 2017	Feb. 07, 2017
Sunoco LP [Member]
Payment Date								May 16, 2017	Feb. 21, 2017
Equity Distribution Agreements, Value of Units Available to be Issued			$ 295			$ 295
Rate								$ 0.8255	$ 0.8255
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement						$ 33
Common Units Issued Inconnection With The Equity Distribution Agreement						1.3
Record Date								May 09, 2017	Feb. 13, 2017
ETE [Member]
Equity Distribution Agreements, Value of Units Available to be Issued			1,000			$ 1,000
Equity distribution agreement [Member] | ETP [Member]
Fees and Commissions						2
Series A Convertible Preferred Units [Member]
Subsidiary units issued						0
Preferred Units, Preferred Partners' Capital Accounts			245			245	$ 180
Noncontrolling Interest, Increase from Sale of Parent Equity Interest						0
Common Unitholders
Subsidiary units issued						(52)
Preferred Units, Preferred Partners' Capital Accounts			$ (1,389)			(1,389)	$ (1,871)
Noncontrolling Interest, Increase from Sale of Parent Equity Interest						$ 42
Convertible Preferred Stock [Member]
Issuance of common units						0.0
Limited Partners' Capital Account, Units Outstanding			329.3			329.3	329.3
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross				$ 2,000
Noncontrolling Interest, Increase from Sale of Parent Equity Interest						$ 1,260
Subsequent Event [Member] | Post-Merger ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		2.50%
Subsequent Event [Member] | ETE [Member]
Relinquishment of Incentive Distributions										$ 499	$ 33	$ 128	$ 153
Bakken Pipeline Investments LLC [Member] | Bakken Holdings Company LLC [Member]
Business Acquisition, Percentage of Voting Interests Acquired														49.00%
Dakota Access and ETCOC [Member] | Bakken Pipeline Investments LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				75.00%
Dakota Access and ETCOC [Member] | Phillips 66 Company [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				25.00%
Sunoco Logistics [Member] | ETP [Member]
Payment Date							Feb. 14, 2017
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				40.00%
Minimum [Member] | PennTex [Member]
Rate						$ 0.2750
Series A Preferred Units [Member] | Sunoco LP [Member]
Payments to Acquire Additional Interest in Subsidiaries			$ 300
Distribution Policy, Members or Limited Partners, Description			The distribution rate of Sunoco LP Series A Preferred Units is 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.
Partners' Capital Account, Units, Sold in Private Placement			12.0
Series A Convertible Preferred Units [Member]
Distribution Made to Limited Partner, Distributions Declared, Per Unit						$ 0.11

[1] Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit.

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Equity Table - Change In ETE Common Units (Details) shares in Millions	3 Months Ended
	Mar. 31, 2017 shares
Class of Stock [Line Items]
Outstanding at December 31, 2016	1,046.9
Issuance of common units	32.2
Outstanding at March 31, 2017	1,079.1
Convertible Preferred Stock [Member]
Class of Stock [Line Items]
Outstanding at December 31, 2016	329.3
Issuance of common units	0.0
Outstanding at March 31, 2017	329.3

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Equity Table - Quarterly Distributions of Available Cash (Details) - $ / shares		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
PennTex [Member]
Record Date		May 05, 2017	Feb. 07, 2017
Payment Date		May 12, 2017	Feb. 14, 2017
Rate		$ 0.2950	$ 0.2950
Parent Company [Member]
Record Date		May 10, 2017	Feb. 07, 2017
Payment Date		May 19, 2017	Feb. 21, 2017
Rate	[1]	$ 0.2850	$ 0.2850
ETP [Member]
Rate			1.0550
Sunoco Logistics [Member]
Rate			$ 0.52
Sunoco LP [Member]
Record Date				May 09, 2017	Feb. 13, 2017
Payment Date				May 16, 2017	Feb. 21, 2017
Rate				$ 0.8255	$ 0.8255
Convertible Units [Member] | Parent Company [Member]
Record Date		May 10, 2017	Feb. 07, 2017
Payment Date		May 19, 2017	Feb. 21, 2017
Rate		$ 0.1100	$ 0.1100

[1] Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit.

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Equity Table - Accumulated Other Comprehensive Income (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 loss related to pensions and other postretirement benefits	5	7
AOCI attributable to equity method investments	4	4
Subtotal	8	8
Amounts attributable to noncontrolling interest	(8)	(8)
Accumulated other comprehensive income, net	$ 0	$ 0

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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 ($)
Lease Expiration Date		Dec. 31, 2034
Operating Leases, Rent Expense, Contingent Rentals		$ 5,000,000	$ 16,000,000
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
Payments for Environmental Liabilities		$ 4,000,000	$ 8,000,000
Site Contingency, Number of Sites Needing Remediation | sites		9
Accrual for Environmental Loss Contingencies		$ 353,000,000			$ 349,000,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		$ 536,000,000
AmeriGas [Member]
Debt Instrument, Interest Rate, Stated Percentage		7.00%
Business Combination, Contingent Consideration, Liability				$ 102,000,000
Contingent Residual Support Agreement, Amount	$ 1,550,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		6
Proposed Environmental Penalty		$ 200,000
Sunoco, Inc. [Member] | Multidistrict Legislation [Member]
Loss Contingency, Pending Claims, Number		4
Williams [Member]
Loss on Contract Termination for Default		$ 410,000,000
Loss Contingency, Damages Sought, Value		10,000,000,000
Williams [Member] | ETE Defendants [Member]
Loss Contingency, Damages Sought, Value		$ 1,480,000,000
Sunoco [Member]
Site Contingency, Number of Sites Needing Remediation		50
Sunoco Logistics [Member]
Payments for Environmental Liabilities		$ 100,000
Proposed Environmental Penalty		$ 100,000

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Rent expense table (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Rental expense(1)	[1]	$ 54	$ 51
Less: Sublease rental income		(6)	(7)
Rental expense, net		$ 48	$ 44

[1] Includes contingent rentals totaling $5 million and $16 million for the three months ended March 31, 2017 and 2016, respectively.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Environmental Exit Cost [Line Items]
Current	$ 32	$ 31
Non-current	321	318
Total environmental liabilities	$ 353	$ 349

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Derivative Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)		3 Months Ended	12 Months Ended
		Mar. 31, 2017 bushels barrels Megawatt bbl MMbtu	Dec. 31, 2016 bushels barrels Megawatt bbl MMbtu	Dec. 31, 2015
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Maximum Term Of Commodity Derivatives
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Maximum Term Of Commodity Derivatives
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Maximum Term Of Commodity Derivatives
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Maximum Term Of Commodity Derivatives
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Maximum Term Of Commodity Derivatives
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Maximum Term Of Commodity Derivatives
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Maximum Term Of Commodity Derivatives		2018	2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Maximum Term Of Commodity Derivatives		2019	2019
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Notional Volume		(5,247,500)
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Notional Volume		(12,185,000)	(5,662,500)
Maximum Term Of Commodity Derivatives		2017		2017
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Notional Volume		(51,102,500)	(52,652,500)
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Notional Volume			(22,492,489)
Maximum Term Of Commodity Derivatives				2017
Natural Gas [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Notional Volume			(682,500)
Maximum Term Of Commodity Derivatives				2017
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Notional Volume		(13,877,500)	(36,370,000)
Maximum Term Of Commodity Derivatives		2017		2017
Natural Gas [Member] | Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member]
Notional Volume		(13,877,500)	(36,370,000)
Maximum Term Of Commodity Derivatives		2017		2017
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Notional Volume			(10,750,000)
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Notional Volume		(16,763,209)
Maximum Term Of Commodity Derivatives		2017
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Notional Volume	[1]	(8,372,500)	(2,242,500)
Maximum Term Of Commodity Derivatives		2017		2017
Natural Gas [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Notional Volume		(80,000)
Maximum Term Of Commodity Derivatives		2017
Natural Gas [Member] | Long [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member]
Notional Volume		(13,877,500)	(36,370,000)
Maximum Term Of Commodity Derivatives		2017		2017
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member]
Maximum Term Of Commodity Derivatives		2017
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Forwards Swaps [Member]
Maximum Term Of Commodity Derivatives		2018	2018
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Future [Member]
Maximum Term Of Commodity Derivatives		2018	2018
Power [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Forwards Swaps [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Power [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Future [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member]
Notional Volume | Megawatt			(50,400)
Maximum Term Of Commodity Derivatives				2017
Power [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Notional Volume | Megawatt		(58,000)
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member]
Notional Volume | Megawatt		(67,200)
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member]
Notional Volume | Megawatt		(447,200)	(186,400)
Maximum Term Of Commodity Derivatives		2017		2017
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member]
Notional Volume | Megawatt		(225,480)	(391,880)
Power [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Notional Volume | Megawatt			(109,564)
WTI Crude Oil [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member]
Notional Volume | bbl		(1,418,000)	(617,000)
Maximum Term Of Commodity Derivatives		2017		2017
Natural Gas Liquids and Crude [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member]
Notional Volume | bbl		(1,827,400)	(5,786,627)
Maximum Term Of Commodity Derivatives		2017		2017
Refined Products [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Notional Volume | barrels		(1,492,000)	(3,144,000)
Maximum Term Of Commodity Derivatives		2017		2017
Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Maximum Term Of Commodity Derivatives		2017
Corn [Member] | Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Notional Volume | bushels		(730,000)
Corn [Member] | Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member]
Notional Volume | bushels			(1,580,000)
Maximum Term Of Commodity Derivatives				2017

[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 Table - Interest Rate Swaps Outstanding (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
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
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%
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 a term 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 Table - Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Total derivatives assets	$ 154	$ 363
Total derivatives liabilities	(351)	(672)
Designated as Hedging Instrument [Member]
Total derivatives assets	0	0
Total derivatives liabilities	(2)	(4)
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	0	0
Total derivatives liabilities	(2)	(4)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	154	363
Total derivatives liabilities	(349)	(668)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	139	338
Total derivatives liabilities	(145)	(416)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	15	25
Total derivatives liabilities	(16)	(58)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	(188)	(193)
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ 0	$ (1)

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Derivative Assets And Liabilities Table - Gross FV and Netting Offset (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 154	$ 363
Derivative Liability, Fair Value, Gross Liability	(351)	(672)
Counterparty netting	(6)	(4)
Counterparty netting	6	4
Payments on margin deposit	(133)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	133	338
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	15	21
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(212)	(330)
Without offsetting agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	188	194
OTC Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15	25
Derivative Liability, Fair Value, Gross Liability	(16)	(58)
Broker cleared derivative contracts [Member]
Derivatives, Fair Value [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 Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (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	19	(71)
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	11	(9)
Commodity Derivatives [Member] | Cost of Products Sold [Member]
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	2	8
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	5	(70)
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 1	$ 0

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Related Party Transactions Related Party Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Related Party Transactions [Abstract]
Revenue from Related Parties	$ 50	$ 81

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Reportable Segments Table - Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,546	$ 1,521
Depreciation, depletion and amortization	661	562
Interest expense, net	486	427
Gains (losses) on interest rate derivatives	5	(70)
Non-cash unit-based compensation expense	(27)	(1)
Unrealized gains (losses) on commodity risk management activities	69	(60)
Losses on extinguishments of debt	(25)	0
Inventory valuation adjustments	(12)	(13)
Equity in earnings of unconsolidated affiliates	87	61
Adjusted EBITDA related to unconsolidated affiliates	(185)	(162)
Other, net	(14)	6
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	325	281
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,414	1,412
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	155	159
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	44	44
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	(13)	(37)
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ (54)	$ (57)

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Reportable Segments Table - Segment Assets (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Assets	$ 80,997	$ 79,011
Investment In ETP [Member]
Assets	72,437	70,191
Investment In Sunoco LP [Member]
Assets	8,454	8,701
Investment in Lake Charles LNG [Member]
Assets	1,540	1,508
Corporate and Other [Member]
Assets	660	711
Adjustments And Eliminations [Member]
Assets	$ (2,094)	$ (2,100)

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Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues	$ 11,247	$ 7,695
Investment In ETP [Member]
Revenues	6,895	4,481
Investment In Sunoco LP [Member]
Revenues	4,394	3,215
Adjustments And Eliminations [Member]
Revenues	(91)	(50)
Intersegment [Member] | Investment In ETP [Member]
Revenues	88	47
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenues	3	3
External Customers [Member] | Investment In ETP [Member]
Revenues	6,807	4,434
External Customers [Member] | Investment In Sunoco LP [Member]
Revenues	4,391	3,212
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues	$ 49	$ 49

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Reportable Segments Table - Revenues from External Customers by Segment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Revenues	$ 11,247	$ 7,695
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	4,394	3,215
Investment In Sunoco LP [Member] | Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues	2,098	1,675
Investment In Sunoco LP [Member] | Wholesale Operations [Member]
Segment Reporting Information [Line Items]
Revenues	2,296	1,540
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	6,895	4,481
Investment In ETP [Member] | Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Revenues	231	254
Investment In ETP [Member] | Midstream [Member]
Segment Reporting Information [Line Items]
Revenues	565	527
Investment In ETP [Member] | Liquids Transportation And Services [Member]
Segment Reporting Information [Line Items]
Revenues	1,508	829
Investment In ETP [Member] | Investment in Sunoco Logistics [Member]
Segment Reporting Information [Line Items]
Revenues	3,185	1,729
Investment In ETP [Member] | Intrastate Transportation And Storage [Member]
Segment Reporting Information [Line Items]
Revenues	768	446
Investment In ETP [Member] | Other operations [Member]
Segment Reporting Information [Line Items]
Revenues	638	696
Intersegment [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	3	3
Intersegment [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	88	47
External Customers [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	4,391	3,212
External Customers [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	$ 6,807	$ 4,434

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Supplemental Financial Statement Information Table - Balance Sheets (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Cash and cash equivalents	$ 370	$ 483	$ 807	$ 606
Accounts receivable, net	3,485	3,557
Accounts receivable from related companies	72	47
Other current assets	513	586
Total current assets	6,514	6,985
Property, plant and equipment, net	56,967	55,438
Advances to and investments in unconsolidated affiliates	3,103	3,040
Intangible assets, net	6,837	5,992
Goodwill	6,750	6,738
Other non-current assets, net	826	818
Total assets	80,997	79,011
Accounts payable	3,363	3,502
Accounts payable to related companies	33	42
Accrued and other current liabilities	2,304	2,367
Total current liabilities	6,218	7,277
Long-term debt, less current maturities	42,583	42,608
Long-term notes payable – related companies	0	250
Other non-current liabilities	1,237	1,123
Commitments and contingencies
General Partner	(3)	(3)
Common Unitholders	(1,389)	(1,871)
Series A Convertible Preferred Units	245	180
Total partners’ capital	(1,147)	(1,694)
Total liabilities and equity	80,997	79,011
Parent Company [Member]
Cash and cash equivalents	3	2	$ 8	$ 1
Accounts receivable, net	2	0
Accounts receivable from related companies	57	55
Total current assets	62	57
Property, plant and equipment, net	35	36
Advances to and investments in unconsolidated affiliates	5,940	5,088
Intangible assets, net	0	1
Goodwill	9	9
Other non-current assets, net	19	10
Total assets	6,065	5,201
Accounts payable	0	1
Accounts payable to related companies	3	22
Interest payable	80	66
Accrued and other current liabilities	3	3
Total current liabilities	86	92
Long-term debt, less current maturities	6,639	6,358
Long-term notes payable – related companies	485	443
Other non-current liabilities	2	2
Commitments and contingencies
General Partner	(3)	(3)
Common Unitholders	(1,389)	(1,871)
Series A Convertible Preferred Units	245	180
Total partners’ capital	(1,147)	(1,694)
Total liabilities and equity	$ 6,065	$ 5,201

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Supplemental Financial Statement Information Schedule of Statements of Operations (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)		$ (197)	$ (168)
Interest expense, net		(486)	(427)
Equity in earnings of unconsolidated affiliates		87	61
Losses on extinguishments of debt		(25)	0
Other, net		19	16
Income tax benefit		35	(55)
NET INCOME		239	312
General Partner’s interest in net income		1	1
Convertible Unitholders’ interest in income		6	0
Limited Partners’ interest in net income		232	311
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	[1]	13	(37)
Interest expense, net		83	(81)
Equity in earnings of unconsolidated affiliates		361	430
Losses on extinguishments of debt		(25)
Other, net		(1)	0
NET INCOME		239	312
General Partner’s interest in net income		1	1
Convertible Unitholders’ interest in income		6	0
Limited Partners’ interest in net income		$ 232	$ 311

[1] Includes management fees paid by ETE to ETP, which management fees will no longer be paid subsequent to March 31, 2017.

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Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Jan. 31, 2017	Mar. 31, 2017	Mar. 31, 2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$ 893	$ 985
Cash paid for Bakken Pipeline Transaction		(330)	(2)
Contributions to unconsolidated affiliate		111	31
Capital expenditures		(1,450)	(1,948)
Net cash used in investing activities		203	(1,942)
Proceeds from borrowings	$ 1,480	9,000	5,750
Repayments of long-term debt		(9,809)	(4,422)
Proceeds from affiliate		106	132
Distributions to partners		(251)	(299)
Debt issuance costs		(53)	(19)
Net cash provided by (used in) financing activities		(1,209)	1,158
INCREASE IN CASH AND CASH EQUIVALENTS		(113)	201
Cash and cash equivalents, beginning of period	483	483	606
Cash and cash equivalents, end of period		370	807
Proceeds from Issuance of Common Limited Partners Units		568	0
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		251	223
Contributions to unconsolidated affiliate		860	65
Capital expenditures		0	(7)
Net cash used in investing activities		(860)	(72)
Proceeds from borrowings		2,017	105
Repayments of long-term debt		(1,733)	0
Proceeds from affiliate		43	50
Distributions to partners		(251)	(299)
Debt issuance costs		(34)	0
Net cash provided by (used in) financing activities		610	(144)
INCREASE IN CASH AND CASH EQUIVALENTS		1	7
Cash and cash equivalents, beginning of period	$ 2	2	1
Cash and cash equivalents, end of period		3	8
Proceeds from Issuance of Common Limited Partners Units		$ 568	$ 0