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 September 30, 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 November 3, 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	42
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59
ITEM 4. CONTROLS AND PROCEDURES	61
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	61
ITEM 1A. RISK FACTORS	62
ITEM 6. EXHIBITS	62
SIGNATURE	63

i

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 the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed on May 4, 2017.

Definitions

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

AmeriGas	AmeriGas Partners, L.P.
AOCI	accumulated other comprehensive income (loss)
Bbls	barrels
Btu	British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
DOJ	U.S. Department of Justice
EPA	Environmental Protection Agency
ETLP Credit Facility	Energy Transfer, LP’s $3.75 billion revolving credit facility
ETP	Energy Transfer Partners, L.P. subsequent to the close of the merger of Sunoco Logistics Partners L.P. and Energy Transfer Partners, L.P.
ETP GP	Energy Transfer Partners GP, L.P., the general partner of ETP
ETP Holdco	ETP Holdco Corporation
ETP LLC	Energy Transfer Partners, L.L.C., the general partner of ETP GP
Exchange Act	Securities Exchange Act of 1934
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
MMBtu	million British thermal units
MTBE	methyl tertiary butyl ether
NGL	natural gas liquid, such as propane, butane and natural gasoline
NYMEX	New York Mercantile Exchange
OSHA	Federal Occupational Safety and Health Act
OTC	over-the-counter

ii

Panhandle	Panhandle Eastern Pipe Line Company, LP
PCBs	polychlorinated biphenyl
PES	Philadelphia Energy Solutions
PennTex	PennTex Midstream Partners, LP
Preferred Units	ETP Series A cumulative convertible preferred units
Regency	Regency Energy Partners LP
Rover	Rover Pipeline LLC
SEC	Securities and Exchange Commission
Series A Convertible Preferred Units	ETE Series A convertible preferred units
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.

iii

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	469		$	463
Accounts receivable, net	3,551			3,557
Accounts receivable from related companies	90			47
Inventories	1,957			2,103
Derivative assets	42			21
Other current assets	433			503
Current assets held for sale	4,147			291
Total current assets	10,689			6,985
Property, plant and equipment	68,730			61,158
Accumulated depreciation and depletion	(9,463		)	(7,905		)
	59,267			53,253
Advances to and investments in unconsolidated affiliates	3,177			3,040
Other non-current assets, net	891			816
Intangible assets, net	6,195			5,489
Goodwill	5,161			5,170
Non-current assets held for sale	—			4,258
Total assets	$	85,380		$	79,011

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

1

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)

	September 30, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,994		$	3,502
Accounts payable to related companies	46			42
Derivative liabilities	129			172
Accrued and other current liabilities	2,881			2,367
Current maturities of long-term debt	716			1,194
Liabilities associated with assets held for sale	81			—
Total current liabilities	7,847			7,277
Long-term debt, less current maturities	44,495			42,608
Long-term notes payable – related company	—			250
Non-current derivative liabilities	132			76
Deferred income taxes	5,027			5,112
Other non-current liabilities	1,218			1,055
Liabilities associated with assets held for sale	—			68
Commitments and contingencies
Preferred units of subsidiary	—			33
Redeemable noncontrolling interests	21			15
Equity:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,566		)	(1,871		)
Series A Convertible Preferred Units	377			180
Total partners’ deficit	(1,192		)	(1,694		)
Noncontrolling interest	27,832			24,211
Total equity	26,640			22,517
Total liabilities and equity	$	85,380		$	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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
REVENUES
Natural gas sales	$	1,098		$	1,070		$	3,132		$	2,603
NGL sales	1,749			1,249			4,782			3,339
Crude sales	2,273			1,649			6,751			4,572
Gathering, transportation and other fees	1,068			1,028			3,244			3,118
Refined product sales	2,706			2,243			7,928			6,249
Other	580			466			1,800			1,346
Total revenues	9,474			7,705			27,637			21,227
COSTS AND EXPENSES
Cost of products sold	7,078			5,776			21,028			15,430
Operating expenses	636			526			1,779			1,540
Depreciation, depletion and amortization	632			548			1,840			1,596
Selling, general and administrative	142			209			484			515
Total costs and expenses	8,488			7,059			25,131			19,081
OPERATING INCOME	986			646			2,506			2,146
OTHER INCOME (EXPENSE)
Interest expense, net	(505		)	(474		)	(1,471		)	(1,336		)
Equity in earnings of unconsolidated affiliates	92			49			228			205
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Losses on extinguishments of debt	—			—			(25		)	—
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Other, net	76			55			168			98
INCOME (LOSS) BEFORE INCOME TAX BENEFIT	641			(60		)	1,378			626
Income tax benefit	(157		)	(89		)	(97		)	(151		)
INCOME FROM CONTINUING OPERATIONS	798			29			1,475			777
Income (loss) from discontinued operations, net of income taxes	6			12			(264		)	24
NET INCOME	804			41			1,211			801
Less: Net income (loss) attributable to noncontrolling interest	552			(168		)	508			39
NET INCOME ATTRIBUTABLE TO PARTNERS	252			209			703			762
General Partner’s interest in net income	1			—			2			2
Convertible Unitholders’ interest in income	11			2			25			3
Limited Partners’ interest in net income	$	240		$	207		$	676		$	757
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.22		$	0.20		$	0.64		$	0.72
Diluted	$	0.22		$	0.19		$	0.62		$	0.71
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.22		$	0.20		$	0.63		$	0.72
Diluted	$	0.22		$	0.19		$	0.61		$	0.71

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

3

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
Net income	$	804	$	41		$	1,211		$	801
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2		—			5			5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	5		—			2			(3		)
Foreign currency translation adjustments	—		—			—			(1		)
Change in other comprehensive income (loss) from unconsolidated affiliates	—		2			(1		)	(9		)
	7		2			6			(8		)
Comprehensive income	811		43			1,217			793
Less: Comprehensive income (loss) attributable to noncontrolling interest	559		(166		)	514			31
Comprehensive income attributable to partners	$	252	$	209		$	703		$	762

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

4

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017

(Dollars in millions)

(unaudited)

	General Partner			Common Unitholders			Series A Convertible Preferred Units			Noncontrolling Interest			Total
Balance, December 31, 2016	$	(3	)	$	(1,871	)	$	180		$	24,211		$	22,517
Distributions to partners	(2		)	(750		)	—			—			(752		)
Distributions to noncontrolling interest	—			—			—			(2,180		)	(2,180		)
Distributions reinvested	—			(173		)	173			—			—
Subsidiary units issued	—			(56		)	(1		)	1,692			1,635
Issuance of common units	—			568			—			—			568
Capital contributions received from noncontrolling interests	—			—			—			1,907			1,907
PennTex unit acquisition	—			(2		)	—			(278		)	(280		)
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			—			69			69
Sale of Bakken Pipeline interest	—			42			—			1,958			2,000
Other comprehensive income, net of tax	—			—			—			6			6
Other, net	—			—			—			(61		)	(61		)
Net income	2			676			25			508			1,211
Balance, September 30, 2017	$	(3	)	$	(1,566	)	$	377		$	27,832		$	26,640

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

5

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Nine Months Ended September 30,
	2017			2016
OPERATING ACTIVITIES
Net income	$	1,211		$	801
Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in an unconsolidated affiliate	—			308
Loss (income) from discontinued operations	264			(24		)
Depreciation, depletion and amortization	1,840			1,596
Deferred income taxes	(120		)	(139		)
Unit-based compensation expense	76			46
Inventory valuation adjustments	(38		)	(203		)
Equity in earnings of unconsolidated affiliates	(228		)	(205		)
Distributions from unconsolidated affiliates	211			190
Other	(134		)	(197		)
Net change in operating assets and liabilities, net of effects of acquisition	222			48
Net cash provided by operating activities	3,304			2,221
INVESTING ACTIVITIES
Proceeds from Bakken Pipeline Transaction	2,000			—
Cash paid for acquisition of PennTex noncontrolling interest	(280		)	—
Cash paid for acquisitions, net of cash received	(293		)	(330		)
Capital expenditures, excluding allowance for equity funds used during construction	(6,102		)	(5,877		)
Contributions to unconsolidated affiliates	(230		)	(47		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	115			112
Other	30			58
Net cash used in investing activities	(4,760		)	(6,084		)
FINANCING ACTIVITIES
Proceeds from borrowings	23,988			18,288
Repayments of long-term debt	(22,586		)	(13,955		)
Cash received from affiliate notes	—			1,606
Cash paid on affiliate notes	(255		)	(1,607		)
Subsidiary units issued for cash	1,635			2,097
Units issued for cash	568			—
Distributions to partners	(752		)	(780		)
Distributions to noncontrolling interest	(2,156		)	(2,027		)
Capital contributions received from noncontrolling interest	919			187
Other	(58		)	110
Net cash provided by financing activities	1,303			3,919
DISCONTINUED OPERATIONS
Operating activities	245			168
Investing activities	(82		)	(359		)
Changes in cash included in current assets held for sale	(4		)	12
Net increase (decrease) in cash and cash equivalents of discontinued operations	159			(179		)
Increase (decrease) in cash and cash equivalents	6			(123		)
Cash and cash equivalents, beginning of period	463			581
Cash and cash equivalents, end of period	$	469		$	458

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

6

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. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P.Under the terms of the transaction, the unitholders received1.5common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately832 millionSunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.

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

At the time of theSunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” 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 “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;

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

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

The consolidated financial statements of 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.

7

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 15 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 for the year ended December 31, 2016 included as Exhibit 99.1 to our Form 8-K filed on October 2, 2017. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliate. Additionally, there were other prior period amounts reclassified to conform to the 2017 presentation. Other than the reclassification of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations, 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

ASU 2014-09

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard.

8

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) 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.

We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of ETP’s reportable segments as well as the accounting for certain processing contracts in ETP’s midstream operations. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.

We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income.

We have substantially completed a detailed review of revenue contracts representative of Sunoco LP’s business segments and their revenue streams; however, we continue to evaluate contract modifications and new contracts that have been or will be entered prior to the adoption date. As a result of the evaluation performed to date, we have determined that the timing and/or amount of revenue that Sunoco LP recognizes on certain contracts will be impacted by the adoption of the new standard; however, we are quantifying these impacts and cannot currently conclude whether or not they would be material to the financial statements.

We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. 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.

ASU 2016-02

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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.

ASU 2016-09

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.

ASU 2016-16

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.

ASU 2016-17

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

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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.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. Sunoco LP early adopted ASC No. 2017-04 during its interim goodwill impairment test in the second quarter of 2017. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

2. ACQUISITIONS AND DIVESTURES

Rover Contribution Agreement

In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.  The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.

Permian Express Partners

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

In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP 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 ETP. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

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 approximately1,112 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 “7-Eleven

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Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.

With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the 7-Eleven purchase agreement.

Sunoco LP Real Estate Sale

In January 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets 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. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketed by the third-party brokerage firm.

The assets under the asset purchase agreement, the 208 Stripes sites and the real estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”).

The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.

The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:

	September 30, 2017		December 31, 2016
Carrying amount of assets classified as held for sale:
Cash and cash equivalents	$	24	$	20
Inventories	183		188
Other current assets	91		83
Property, plant and equipment, net	2,132		2,185
Goodwill	1,216		1,568
Intangible assets, net	499		503
Other non-current assets, net	2		2
Total assets classified as held for sale in the Consolidated Balance Sheet	$	4,147	$	4,549
Carrying amount of liabilities classified as held for sale:
Other current and non-current liabilities	81		68
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	81	$	68

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The results of operations associated with discontinued operations are presented in the following table:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
REVENUES	$	2,312	$	1,970	$	6,580		$	5,474
COSTS AND EXPENSES
Cost of products sold	1,927		1,585		5,478			4,445
Operating expenses	236		250		727			727
Depreciation, depletion and amortization	5		47		68			149
Selling, general and administrative	57		37		122			74
Total costs and expenses	2,225		1,919		6,395			5,395
OPERATING INCOME	87		51		185			79
Interest expense, net	13		7		22			22
Other, net	38		1		367			4
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)	36		43		(204		)	53
Income tax expense	30		31		60			29
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	6	$	12	$	(264	)	$	24
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE	$	—	$	—	$	(9	)	$	—

In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $320 million recognized in the three months ended June 30, 2017 and $44 million recognized in the three months ended September 30, 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 be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Non-cash investing activities were as follows:

	Nine Months Ended September 30,
	2017			2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,237		$	1,001
Losses from subsidiary common unit issuances, net	(57		)	(3		)
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988		$	—

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4. INVENTORIES

Inventories consisted of the following:

	September 30, 2017		December 31, 2016
Natural gas and NGLs	$	609	$	699
Crude oil	696		683
Refined products	413		483
Other	239		238
Total inventories	$	1,957	$	2,103

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 September 30, 2017 were $47.21 billion and $45.21 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations were $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 and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the nine months endedSeptember 30, 2017, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 based on inputs used to derive their fair values:

				Fair Value Measurements at September 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—
Swing Swaps IFERC	2			—			2
Fixed Swaps/Futures	28			28			—
Forward Physical Swaps	3			—			3
Power:
Forwards	11			—			11
Futures	1			1			—
Options — Puts	1			1			—
Natural Gas Liquids – Forwards/Swaps	213			213			—
Refined Products — Futures	4			4			—
Crude – Futures	2			2			—
Total commodity derivatives	281			265			16
Total assets	$	281		$	265		$	16
Liabilities:
Interest rate derivatives	$	(210	)	$	—		$	(210	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(22		)	(22		)	—
Swing Swaps IFERC	(3		)	(1		)	(2		)
Fixed Swaps/Futures	(22		)	(22		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(9		)	—			(9		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(261		)	(261		)	—
Refined Products — Futures	(3		)	(3		)	—
Crude — Futures	(1		)	(1		)	—
Total commodity derivatives	(323		)	(311		)	(12		)
Total liabilities	$	(533	)	$	(311	)	$	(222	)

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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 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 September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
Income from continuing operations	$	798	$	29		$	1,475		$	777
Less: Income (loss) from continuing operations attributable to noncontrolling interest	546		(180		)	763			15
Income from continuing operations, net of noncontrolling interest	252		209			712			762
Less: General Partner’s interest in income	1		—			2			2
Less: Convertible Unitholders’ interest in income	11		2			25			3
Income from continuing operations available to Limited Partners	$	240	$	207		$	685		$	757
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,079.1		1,045.5			1,077.9			1,045.0
Basic income from continuing operations per Limited Partner unit	$	0.22	$	0.20		$	0.64		$	0.72
Basic loss from discontinued operations per Limited Partner unit	$	0.00	$	0.00		$	(0.01	)	$	0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	240	$	207		$	685		$	757
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	10		2			25			3
Diluted income from continuing operations available to Limited Partners	$	250	$	209		$	710		$	760
Weighted average limited partner units	1,079.1		1,045.5			1,077.9			1,045.0
Dilutive effect of unconverted unit awards and Convertible Units	69.2		55.2			69.4			26.3
Diluted weighted average limited partner units	1,148.3		1,100.7			1,147.3			1,071.3
Diluted income from continuing operations per Limited Partner unit	$	0.22	$	0.19		$	0.62		$	0.71
Diluted loss from discontinued operations per Limited Partner unit	$	0.00	$	0.00		$	(0.01	)	$	0.00

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.

Energy Transfer Equity, L.P. Senior Notes Offering 

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.

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The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.

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 ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, 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 27.5 million common units representing limited partner interests in 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 ETP. The Term Loan Facility 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.

On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.

In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.

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 September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.

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Subsidiary Indebtedness

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 September 30, 2017, the balance on the term loan was $1.24 billion.

ETP Senior Notes Redemption

In October 2017, ETP redeemed all of the outstanding$500 millionaggregate principal amount of ETLP’s6.50%senior notes due July 2021 and all of the outstanding$700 millionaggregate principal amount of ETLP’s5.50%senior notes due April 2023.The aggregate amount paid to redeem these notes, including call premiums, was approximately$1.23 billion.

ETP Senior Notes Offering

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued$750 millionaggregate principal amount of4.00%senior notes due 2027 and$1.50 billionaggregate principal amount of5.40%senior notes due 2047. The$2.22 billionnet proceeds from the offering were used to redeem all of the$500 millionaggregate principal amount of ETLP’s6.5%senior notes due 2021, to repay borrowings outstanding under the Sunoco LogisticsCredit Facility (described below) and for general partnership purposes.

The senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal is payable upon maturity. Interest on the senior notes is paid semi-annually. The senior notes are guaranteed by ETP on a senior unsecured basis as long as it guarantees any of Sunoco Logistics Partners Operations L.P.’s other long-term debt.As a result of the parent guarantee, the senior notes will rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any subordinated debt ETP may incur.  

ETLP Credit Facility

The ETLP Credit Facility allows for borrowings of up to$3.75 billionand matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the$3.75 billionETLP Credit Facility.As ofSeptember 30, 2017, the ETLP Credit Facility had$2.06 billionof outstanding borrowings, all of which was commercial paper.

Sunoco Logistics Credit Facilities

ETP maintains the Sunoco Logistics$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 ofSeptember 30, 2017, the Sunoco Logistics Credit Facility had$35 millionof outstanding borrowings.

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

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 September 30, 2017, the Sunoco LP credit facility had $644 million of outstanding borrowings and $9 million in standby letters of credit. The unused availability on the revolver at September 30, 2017 was $847 million.

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On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Agreement with the lenders party thereto and Bank of America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.

Bakken Credit Facility

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

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”).In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

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 September 30, 2017.

8. PREFERRED UNITS

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

9. EQUITY

ETE

The changes in ETE common units and Convertible Units during the nine months ended September 30,2017 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 September 30, 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 nine months endedSeptember 30, 2017.

Series A Convertible Preferred Units

As of September 30, 2017, the Partnership had 329.3 million Series A Convertible Preferred Units outstanding with a carrying value of $377 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 23.7 million newly issued ETP common units for approximately $568 million.

Repurchase Program

During the nine months endedSeptember 30, 2017, ETE did not repurchase any ETE common units under its current buyback program. As of September 30, 2017, $936 million remained available to repurchase under the current program.

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Subsidiary Equity 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 nine months endedSeptember 30, 2017, we recognized decreases in partners’ capital of $57 million.

ETP Common Unit Transaction

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion. During thenine months ended September 30,2017, ETP received proceeds of $498 million, net of$5 millionof commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan. During the nine months endedSeptember 30, 2017, distributions of$106 millionwere reinvested under the distribution reinvestment plan.

ETP August 2017 Units Offering

In August 2017, ETP issued54 millionETP common unitsin an underwritten public offering. Net proceeds of$997 millionfrom the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100%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 and ETCO.The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

PennTex Tender Offer and Limited Call Right Exercise

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

Sunoco LP Common Unit Transactions

During the nine months ended September 30,2017, 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 September 30, 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.

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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
June 30, 2017 (1)	August 7, 2017	August 21, 2017	$	0.2850
September 30, 2017 (1)	November 7, 2017	November 20, 2017	0.2950

⁽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
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 2017	0.1100

ETP Quarterly Distributions of Available Cash

Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP's business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

If cash distributions exceed$0.0833per unit in a quarter, the general partner receives increasing percentages, up to50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

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

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

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 15, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 14, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650

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

	Total Year
2017 (remainder)	$	173
2018	153
2019	128
Each year beyond 2019	33

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
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 2017	0.8255

Accumulated Other Comprehensive Income

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

	September 30, 2017			December 31, 2016
Available-for-sale securities	$	7		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	9			7
Investments in unconsolidated affiliates, net	3			4
Subtotal	14			8
Amounts attributable to noncontrolling interest	(14		)	(8		)
Total AOCI, net of tax	$	—		$	—

10. INCOME TAXES

For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately$68 million during the periods presented. The remainder of the increase in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. For the three and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.

11. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012,ETLP (formerly Energy Transfer Partners, L.P.)agreed to provide contingent residual support of$1.55 billionof intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETLP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its7.00%senior notes. The remaining outstanding7.00%senior notes were repurchased in May 2017, and ETLP no longer provides contingent residual support for any AmeriGas notes.

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FERC Audit

In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.

Commitments

In the normal course of 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 2047.  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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Rental expense	$	42		$	31		$	106		$	94
Less: Sublease rental income	(6		)	(6		)	(19		)	(18		)
Rental expense, net	$	36		$	25		$	87		$	76

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

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

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

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The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.

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

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

On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete this additional work by April 2018. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relating to its remand order.

While we believe that the pending lawsuits are unlikely to block operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.

MTBE Litigation

Sunoco, Inc. and/or Sunoco, Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically governmental authorities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As ofSeptember 30, 2017, Sunoco, Inc. is a defendant insixcases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, Rhode Island, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action.Fourof these cases are venued in a multidistrict litigation proceeding in a New York federal court.

Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The court approved the Judicial Consent Order on October 10, 2017.

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It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).

The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Merger Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. A hearing on these motions is currently set for January 9, 2018.

The Regency Merger Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Merger Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.

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

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of$319 millionin compensatory damages and$595 millionin disgorgement to ETP.  The jury also found that ETP owed Enterprise approximately$1 millionunder a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP$536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP intends to file a petition for review with the Texas Supreme Court.

Sunoco Logistics Merger Litigation

Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits have been voluntarily dismissed. The five remaining lawsuits have been consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”).The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”).The ETP Unitholder Plaintiffs seek rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees.

The ETP-SXL Defendants cannot predict the outcome of the Sunoco Logistics Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing, nor can the ETP-SXL Defendants predict the amount of time and expense that will be required to resolve the Sunoco Logistics Merger Litigation. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Sunoco Logistics Merger.

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Litigation Filed By or Against Williams

On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams 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 Williams Litigation. The counterclaim asserts in general that Williams 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 Williams’ 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 a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.

On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that 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 concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams 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.

ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams 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, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. 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 a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware WMB Litigation 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 Williams’ requests for injunctive relief. The Court did not reach Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.

Williams filed an amended complaint on September 16, 2016 and sought 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 Defendants breached an additional representation and warranty in the Merger Agreement.

Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought 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 Defendants’ amended counterclaims and to strike certain of 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 March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

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Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

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 (collectively, the “Issuance Defendants”) 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 (the “Issuance Litigation”). 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.

On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.

The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.

The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance.

Litigation filed by BP Products

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

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.

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

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

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Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of September 30, 2017 and December 31, 2016, accruals of approximately $68 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations.  As new information becomes available, our estimates may change.  The impact of these changes may have a significant effect on our results of operations in a single period.

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

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

The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of approximately $2.3 millionin connection with the alleged violations and is seeking certain corrective actions. ETP is working with Ohio EPA to resolve the matter. The timing or outcome of this matter cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at27sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.

On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  On August 1, 2017 the EHB lifted the order as to two drill locations.  On August 3, 2017, the EHB lifted the order as to 14 additional locations.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting.  On August 7, 2017 a final settlement was reached.  A stipulated order has been submitted to the EHB Judge with respect to the settlement.  The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.

In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those

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agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.

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

Environmental Matters

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

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

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

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

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

• Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.

• Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

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

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

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• Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As ofSeptember 30, 2017, Sunoco, Inc. had been named as a PRP at approximately44identified 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.

	September 30, 2017		December 31, 2016
Current	$	42	$	31
Non-current	302		318
Total environmental liabilities	$	344	$	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 September 30,2017 and 2016, the Partnership recorded $7 million and $12 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2017 and 2016, the Partnership recorded $22 million and $31 million, respectively.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of$200,000to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

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12. DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, 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 ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s 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 ETP’s midstream segment whereby its 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 ETP’s NGL and refined products transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

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

We use 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 ETP’s 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 ETP’s 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 ETP’s 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:

	September 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,297,500		2017-2018	(682,500	)	2017
Basis Swaps IFERC/NYMEX (1)	(15,810,000	)	2017-2019	2,242,500		2017
Options – Puts	13,000,000		2018	—		—
Power (Megawatt):
Forwards	665,040		2017-2018	391,880		2017-2018
Futures	(213,840	)	2017-2018	109,564		2017-2018
Options — Puts	(280,800	)	2017-2018	(50,400	)	2017
Options — Calls	545,600		2017-2018	186,400		2017
Crude (Bbls):
Futures	(160,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	67,500		2017-2020	10,750,000		2017-2018
Swing Swaps IFERC	91,897,500		2017-2019	(5,662,500	)	2017
Fixed Swaps/Futures	(20,220,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(140,937,993	)	2017-2018	(22,492,489	)	2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(8,744,200	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) — Futures	(1,947,000	)	2017-2018	(3,144,000	)	2017
Corn (Bushels) — Futures	650,000		2017-2018	1,580,000		2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(41,102,500	)	2017	(36,370,000	)	2017
Hedged Item — Inventory	41,102,500		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)	September 30, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

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

⁽²⁾  Represents the effective date. These forward-starting swaps have 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
	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	7	$	—	$	—		$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	222	$	338	$	(262	)	$	(416	)
Commodity derivatives	52		25		(61		)	(58		)
Interest rate derivatives	—		—		(210		)	(193		)
Embedded derivatives in the ETP Preferred Units	—		—		—			(1		)
	274		363		(533		)	(668		)
Total derivatives	$	281	$	363	$	(533	)	$	(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	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(210	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	52			25			(61		)	(58		)
Broker cleared derivative contracts	Other current assets	229			338			(262		)	(420		)
Total gross derivatives		281			363			(533		)	(672		)
Less offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(10		)	(4		)	10			4
Payments on margin deposit	Other current assets	(220		)	(338		)	220			338
Total net derivatives		$	51		$	21		$	(303	)	$	(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 September 30,					Nine Months Ended September 30,
		2017		2016			2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	2	$	(9	)	$	4	$	8
Total		$	2	$	(9	)	$	4	$	8

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading	Cost of products sold	$	(5	)	$	(7	)	$	21		$	(24	)
Commodity derivatives —Non-trading	Cost of products sold	(25		)	(16		)	(6		)	(61		)
Interest rate derivatives	Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Embedded derivatives	Other, net	—			8			1			4
Total		$	(38	)	$	(43	)	$	(12	)	$	(260	)

13. RELATED PARTY TRANSACTIONS

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

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 expired in 2016.

In addition, ETE recorded sales with affiliates of $105 million and $49 million during the three months endedSeptember 30, 2017 and 2016, respectively, and $201 million and $175 million during the nine months endedSeptember 30, 2017 and 2016, respectively.

14.    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

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• 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.

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Investment in ETP	$	1,744		$	1,390		$	4,757		$	4,172
Investment in Sunoco LP	199			189			574			512
Investment in Lake Charles LNG	43			45			131			133
Corporate and Other	(3		)	(37		)	(25		)	(142		)
Adjustments and Eliminations	(74		)	(83		)	(211		)	(208		)
Total	1,909			1,504			5,226			4,467
Depreciation, depletion and amortization	(632		)	(548		)	(1,840		)	(1,596		)
Interest expense, net	(505		)	(474		)	(1,471		)	(1,336		)
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Non-cash unit-based compensation expense	(29		)	(23		)	(76		)	(46		)
Unrealized gains (losses) on commodity risk management activities	(76		)	(21		)	22			(105		)
Losses on extinguishments of debt	—			—			(25		)	—
Inventory valuation adjustments	141			35			38			203
Equity in earnings of unconsolidated affiliates	92			49			228			205
Adjusted EBITDA related to unconsolidated affiliates	(205		)	(157		)	(554		)	(503		)
Adjusted EBITDA related to discontinued operations	(92		)	(93		)	(253		)	(220		)
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Other, net	46			4			111			44
Income (loss) before income tax benefit	$	641		$	(60	)	$	1,378		$	626

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	September 30, 2017			December 31, 2016
Assets:
Investment in ETP	$	77,011		$	70,191
Investment in Sunoco LP	8,307			8,701
Investment in Lake Charles LNG	1,611			1,508
Corporate and Other	620			711
Adjustments and Eliminations	(2,169		)	(2,100		)
Total assets	$	85,380		$	79,011

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Investment in ETP:
Revenues from external customers	$	6,876		$	5,488		$	20,168		$	15,167
Intersegment revenues	97			43			276			134
	6,973			5,531			20,444			15,301
Investment in Sunoco LP:
Revenues from external customers	2,549			2,167			7,321			5,912
Intersegment revenues	6			—			9			6
	2,555			2,167			7,330			5,918
Investment in Lake Charles LNG:
Revenues from external customers	49			50			148			148
Adjustments and Eliminations	(103		)	(43		)	(285		)	(140		)
Total revenues	$	9,474		$	7,705		$	27,637		$	21,227

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Intrastate Transportation and Storage	$	729	$	583	$	2,196	$	1,457
Interstate Transportation and Storage	220		231		652		714
Midstream	665		582		1,863		1,799
NGL and refined products transportation and services	1,989		1,397		5,874		4,014
Crude oil transportation and services	2,714		1,856		7,749		5,146
All Other	656		882		2,110		2,171
Total revenues	6,973		5,531		20,444		15,301
Less: Intersegment revenues	97		43		276		134
Revenues from external customers	$	6,876	$	5,488	$	20,168	$	15,167

The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger.

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Investment in Sunoco LP

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Retail operations	$	88	$	80	$	247	$	241
Wholesale operations	2,467		2,087		7,083		5,677
Total revenues	2,555		2,167		7,330		5,918
Less: Intersegment revenues	6		—		9		6
Revenues from external customers	$	2,549	$	2,167	$	7,321	$	5,912

Investment in Lake Charles LNG

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

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15. 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)

	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	2
Accounts receivable from related companies	64			55
Other current assets	2			—
Total current assets	66			57
Property, plant and equipment, net	27			36
Advances to and investments in unconsolidated affiliates	6,031			5,088
Intangible assets, net	—			1
Goodwill	9			9
Other non-current assets, net	17			10
Total assets	$	6,150		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	1
Accounts payable to related companies	—			22
Interest payable	79			66
Accrued and other current liabilities	3			3
Total current liabilities	82			92
Long-term debt, less current maturities	6,684			6,358
Long-term notes payable – related companies	574			443
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ capital:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,566		)	(1,871		)
Series A Convertible Preferred Units	377			180
Total partners’ deficit	(1,192		)	(1,694		)
Total liabilities and equity	$	6,150		$	5,201

39

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(3	)	$	(75	)	$	(25	)	$	(156	)
OTHER INCOME (EXPENSE):
Interest expense, net	(88		)	(81		)	(257		)	(244		)
Equity in earnings of unconsolidated affiliates	343			367			1,012			1,166
Losses on extinguishments of debt	—			—			(25		)	—
Other, net	—			(2		)	(2		)	(4		)
NET INCOME	252			209			703			762
General Partner’s interest in net income	1			—			2			2
Convertible Unitholders’ interest in income	11			2			25			3
Limited Partners’ interest in net income	$	240		$	207		$	676		$	757

⁽¹⁾  Prior periods include 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)

	Nine Months Ended September 30,
	2017			2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	620		$	718
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(861		)	(70		)
Capital expenditures	(1		)	(15		)
Contributions in aid of construction costs	7			—
Net cash used in investing activities	(855		)	(85		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,116			180
Principal payments on debt	(1,795		)	(155		)
Proceeds from affiliate	131			129
Distributions to partners	(752		)	(780		)
Units issued for cash	568			—
Debt issuance costs	(35		)	—
Net cash provided by (used in) financing activities	233			(626		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(2		)	7
CASH AND CASH EQUIVALENTS, beginning of period	2			1
CASH AND CASH EQUIVALENTS, end of period	$	—		$	8

41

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

AND RESULTS OF OPERATIONS

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

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in Exhibit 99.1 to the Partnership’s Form 8-K filed with the SEC on October 2, 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 September 30, 2017, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 27.5 million ETP common units, 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries.

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 Senior Notes Offering 

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.

ETE January 2017 Private Placement and Energy Transfer Partners, L.P. 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 23.7 million newly issued Energy Transfer Partners, L.P. common units.

ETP Senior Notes Redemption

In October 2017, ETP redeemed all of the outstanding$500 millionaggregate principal amount of ETLP’s6.50%senior notes due July 2021 and all of the outstanding$700 millionaggregate principal amount of ETLP’s5.50%senior notes due April 2023.The aggregate amount paid to redeem these notes, including call premiums, was approximately$1.23 billion.

ETP Senior Notes Offering

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued$750 millionaggregate principal amount of4.00%senior notes due 2027 and$1.50 billionaggregate principal amount of5.40%senior notes due 2047. The$2.22 billionnet proceeds from the offering were used to redeem all of the$500 millionaggregate principal amount of ETLP’s6.5%senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for general partnership purposes.

42

ETP August 2017 Units Offering

In August 2017, ETP issued54 millionETP common unitsin an underwritten public offering. Net proceeds of$997 millionfrom the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

Rover Contribution Agreement

In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.  The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.

PennTex Tender Offer and Limited Call Right Exercise

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

Sunoco Logistics Merger

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P.Under the terms of the transaction, the unitholders received1.5common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.

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 1,112 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 “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.

With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligations related to the divested retail 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 Real Estate Sale

In January 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets 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. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketed by the third-party brokerage firm.

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Permian Express Partners

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

In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP 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 ETP. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100%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 and ETCO.The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

Quarterly Cash Distribution

In October 2017, ETE announced its quarterly distribution of $0.295 per unit ($1.18 annualized) on ETE common units for the quarter ended September 30, 2017.

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.

44

Consolidated Results

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017			2016			Change			2017			2016			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,744		$	1,390		$	354		$	4,757		$	4,172		$	585
Investment in Sunoco LP	199			189			10			574			512			62
Investment in Lake Charles LNG	43			45			(2		)	131			133			(2		)
Corporate and Other	(3		)	(37		)	34			(25		)	(142		)	117
Adjustments and Eliminations	(74		)	(83		)	9			(211		)	(208		)	(3		)
Total	1,909			1,504			405			5,226			4,467			759
Depreciation, depletion and amortization	(632		)	(548		)	(84		)	(1,840		)	(1,596		)	(244		)
Interest expense, net	(505		)	(474		)	(31		)	(1,471		)	(1,336		)	(135		)
Losses on interest rate derivatives	(8		)	(28		)	20			(28		)	(179		)	151
Non-cash unit-based compensation expense	(29		)	(23		)	(6		)	(76		)	(46		)	(30		)
Unrealized gains (losses) on commodity risk management activities	(76		)	(21		)	(55		)	22			(105		)	127
Losses on extinguishments of debt	—			—			—			(25		)	—			(25		)
Inventory valuation adjustments	141			35			106			38			203			(165		)
Equity in earnings of unconsolidated affiliates	92			49			43			228			205			23
Adjusted EBITDA related to unconsolidated affiliates	(205		)	(157		)	(48		)	(554		)	(503		)	(51		)
Adjusted EBITDA related to discontinued operations	(92		)	(93		)	1			(253		)	(220		)	(33		)
Impairment of investment in an unconsolidated affiliate	—			(308		)	308			—			(308		)	308
Other, net	46			4			42			111			44			67
Income (loss) before income tax benefit	641			(60		)	701			1,378			626			752
Income tax benefit	(157		)	(89		)	(68		)	(97		)	(151		)	54
Income from continuing operations	798			29			769			1,475			777			698
Income (loss) from discontinued operations, net of income taxes	6			12			(6		)	(264		)	24			(288		)
Net income	$	804		$	41		$	763		$	1,211		$	801		$	410

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three and nine months endedSeptember 30, 2017 compared to the same period last year increased primarily due to additional depreciation and amortization from assets recently placed in service.

Interest Expense, Net. Interest expense for the three and nine months endedSeptember 30, 2017 increased primarily due to the following:

• increase of $4 million of expense recognized by Sunoco LP for the three months ended September 30, 2017 compared to the same period in the prior year primarily due to higher interest rates on Sunoco LP’s borrowings under its revolving credit facility that Sunoco LP entered into in September 2014 and an increase of $51 million of expense for the nine months ended September 30, 2017 compared to the same period in the prior year due to the issuance of Sunoco LP’s

45

$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

• increases of $22 million and $71 million, respectively, of expense recognized by ETP primarily attributable to increases in long-term debt, including the Dakota Access and ETCO term loans that became effective in August 2016.

Losses on Interest Rate Derivatives. Losses on interest rate derivativesduring the three and nine months ended September 30, 2017 and 2016 resulted from decreases in forward interest rates.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in the segment results below.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded during the three and nine months endedSeptember 30, 2017 and 2016, for the inventory associated with ETP’s crude oil transportation and service and ETP’s NGL and refined products transportation and services inventories as a result of commodity price changes during the respective periods.

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

Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that is classified as held for sale.

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

Income Tax (Expense) Benefit. For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately$68 million during the periods presented. The remainder of the increase in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. For the three and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.

Segment Operating Results

Investment in ETP

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017			2016			Change			2017			2016			Change
Revenues	$	6,973		$	5,531		$	1,442		$	20,444		$	15,301		$	5,143
Cost of products sold	4,876			3,844			1,032			14,582			10,280			4,302
Unrealized (gains) losses on commodity risk management activities	81			15			66			(17		)	96			(113		)
Operating expenses, excluding non-cash compensation expense	(525		)	(464		)	(61		)	(1,543		)	(1,349		)	(194		)
Selling, general and administrative, excluding non-cash compensation expense	(95		)	(76		)	(19		)	(302		)	(239		)	(63		)
Inventory valuation adjustments	(86		)	(37		)	(49		)	(30		)	(143		)	113
Adjusted EBITDA related to unconsolidated affiliates	279			240			39			765			711			54
Other	(7		)	25			(32		)	22			75			(53		)
Segment Adjusted EBITDA	$	1,744		$	1,390		$	354		$	4,757		$	4,172		$	585

Segment Adjusted EBITDA. For the three months ended September 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP increased due to the net impact of the following:

46

• an increase of $30 million in ETP’s intrastate transportation and storage operations resulting from an increase of $29 million due to higher realized gains from pipeline optimization activity and an increase of $9 million in storage margin. These increases were offset by a decrease in transportation fees due to renegotiated contracts;

• an increase of $42 million in ETP’s midstream operations primarily due to a $24 million increase in non-fee based margins due to higher realized crude oil and NGL prices and a $31 million increase in fee-based revenues due to minimum volume commitments in South Texas, increased volumes in the Permian and Northeast regions, and recent acquisitions, including PennTex;

• an increase of $40 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $20 million, primarily due to higher volumes on Texas NGL pipelines and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $14 million, primarily due to higher NGL volumes from most major producing regions; and an increase in terminal services margin of $7 million due to higher terminal volumes from the Mariner NGL projects; partially offset by an increase in operating expenses due to a legal settlement and a quarterly ad valorem tax true-up;

• an increase of $227 million in ETP’s crude oil transportation and services operations due to an increase of $194 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $28 million from existing assets due to increased volumes throughout the system; and an increase of $18 million due to the impact of LIFO accounting; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; and

• an increase of approximately $20 million in ETP’s all other operations, primarily due to an increase of $25 million in Adjusted EBITDA related to ETP’s investment in PES of $34 million, offset by decrease of $9 million from ETP’s investment in Sunoco LP. In addition, the three months ended September 30, 2017 experienced an increase of $7 million from commodity trading activities and an increase of $4 million from ETP’s compression operations. These increases were partially offset by higher transaction related expenses, and operating and maintenance expenses from an equipment lease buyout; partially offset by

• a decrease of $5 million in ETP’s interstate transportation and storage operations due to an aggregate $12 million decrease in revenue, including decreases on the Panhandle, Trunkline and Transwestern pipelines primarily due to lack of customer demand driven by weak spreads and mild weather, and a decrease of $3 million revenues on the Tiger pipeline due to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipeline being placed in partial service in August 2017 and by higher income from unconsolidated joint ventures of $9 million primarily due to a legal settlement and lower operating expenses on Citrus.

Segment Adjusted EBITDA. For the nine months endedSeptember 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP increased due to the net impact of the following:

• an increase of $19 million in ETP’s intrastate transportation and storage operations resulting from a $63 million increase due to higher realized gains from pipeline optimization offset by a $44 million decrease in transportation fees due to renegotiated contracts;

• an increase of $213 million in ETP’s midstream operations primarily due to a $151 million increase in non-fee based margins due to higher realized crude oil and NGL prices and increased volumes in the Permian region and a $93 million increase in fee-based revenues due to minimum volume commitments in South Texas as well as increased volumes in the Permian and Northeast regions, and recent acquisitions, including PennTex. These increases in gross margin were partially offset by increases in operating expenses of $17 million due to recent acquisitions and increases in selling, general and administrative expenses due to a decrease in capitalized overhead, an increase in shared services allocation, an increase in insurance allocation and additional costs from the PennTex acquisition;

• an increase of $124 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $91 million, primarily due to higher volumes on Texas NGL pipelines and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $56 million, primarily due to higher NGL volumes from most major producing regions; and an increase of $22 million in marketing margin (excluding changes in unrealized gains of $50 million) primarily due to the timing of the recognition of margin from optimization activities; partially offset by an increase of $39 million in operating expenses primarily due to increased utilities costs associated with our fourth fractionator at Mont Belvieu and the Mariner project ramp up at the Marcus Hook Industrial Complex; and

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• an increase of $309 million in ETP’s crude oil transportation and services operations due to an increase of $389 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; and an increase of $11 million from existing assets due to increased volumes throughout the system; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; partially offset by

• a decrease of $48 million in ETP’s interstate transportation and storage operations due to an aggregate $63 million decrease in revenue, including decreases on the Panhandle, Trunkline and Transwestern pipelines primarily due to lack of customer demand driven by weak spreads and mild weather, and a decrease of $17 million revenues on the Tiger pipeline due to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipeline being placed in partial service in August 2017 and by lower operating expenses and selling, general and administrative expenses as well as an increase in income from unconsolidated joint ventures of $7 million primarily due to a legal settlement and lower operating expenses on Citrus offset by lower earnings from Midcontinent Express; and

• a decrease of approximately $32 million in ETP’s all other operations, primarily due to a decrease of $66 million related to the termination of ETP’s management fees paid by ETE that ended in 2016 and an increase of $39 million in transaction related expenses partially offset by an increase of $35 million in Adjusted EBITDA related to unconsolidated affiliates, primarily comprising increases of $29 million from ETP’s investment in PES and $3 million from ETP’s investment in Sunoco LP, an increase of $15 million from commodity trading activities and lower expenses related to ETP’s compression operations.

Investment in Sunoco LP

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017			2016			Change			2017			2016			Change
Revenues	$	2,555		$	2,167		$	388		$	7,330		$	5,918		$	1,412
Cost of products sold	2,304			1,975			329			6,730			5,290			1,440
Operating expenses, excluding non-cash compensation expense	(62		)	(62		)	—			(182		)	(171		)	(11		)
Selling, general and administrative, excluding non-cash compensation expense	(21		)	(42		)	21			(84		)	(119		)	35
Inventory valuation adjustments	(56		)	1			(57		)	(8		)	(60		)	52
Unrealized gains (losses) on commodity risk management activities	(5		)	6			(11		)	(5		)	9			(14		)
Adjusted EBITDA from discontinued operations	92			93			(1		)	253			220			33
Other	—			1			(1		)	—			5			(5		)
Segment Adjusted EBITDA	$	199		$	189		$	10		$	574		$	512		$	62

Segment Adjusted EBITDA. For the three months endedSeptember 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:

• an increase in wholesale motor fuel revenue due to a higher sales price per wholesale motor fuel gallon, and an increase in wholesale motor fuel gallons sold offset by higher cost of products sold, excluding a $56 million favorable inventory adjustment change from 2016;

• a net increase in other revenue consisting of merchandise, rental income and retail motor fuel of $8 million; and

• a decrease in selling, general and administrative expenses of $21 million primarily due to higher costs in 2016 related to relocation, employee termination, and higher contract labor and professional fees as Sunoco LP transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas, to Dallas during 2016.

Segment Adjusted EBITDA. For the nine months endedSeptember 30, 2017 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in Sunoco LP increased due to the net impact of the following:

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• an increase in wholesale motor fuel revenue due to a higher sales price per wholesale motor fuel gallon, and an increase in wholesale motor fuel gallons sold offset by higher cost of products sold primarily due to an unfavorable inventory adjustment changes;

• a decrease in selling, general and administrative expenses of $35 million primarily due to higher costs in 2016 related to relocation, employee termination, and higher contract labor and professional fees as Sunoco LP transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas, to Dallas during 2016; and

• an increase in adjusted EBITDA from discontinued operations of $33 million primarily due to an increase of $73 million in the gross profit offset by an increase of $48 million in selling, general and administrative expenses related to discontinued operations; partially offset by

• an increase in other operating expenses of $11 million primarily attributable to the acquisition of the fuels business from Emerge Energy Services LP in August of 2016 as well as increases of utilities, maintenance expenses, property taxes and credit card processing fees in our retail business.

Investment in Lake Charles LNG

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017			2016			Change			2017			2016			Change
Revenues	$	49		$	50		$	(1	)	$	148		$	148		$	—
Operating expenses, excluding non-cash compensation expense	(6		)	(4		)	(2		)	(15		)	(13		)	(2		)
Selling, general and administrative, excluding non-cash compensation expense	—			(1		)	1			(2		)	(2		)	—
Segment Adjusted EBITDA	$	43		$	45		$	(2	)	$	131		$	133		$	(2	)

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

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

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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.

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 $150 million on growth capital and $70 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.

Nine months ended September 30,2017 compared to nine months ended September 30,2016. Cash provided by operating activities during 2017 was $3.30 billion as compared to $2.22 billion for 2016. Net income was $1.21 billion and $801 million for 2017 and 2016, respectively. The difference between net income and the net cash provided by operating activities for the nine months ended September 30,2017 and 2016, primarily consisted of non-cash items totaling $1.40 billion and $898 million, respectively, and net changes in operating assets and liabilities of $222 million and $48 million, respectively. The nine months ended September 30, 2016, included a $308 million impairment of investment in an unconsolidated affiliate.

The non-cash activity in 2017 and 2016 consisted primarily of depreciation, depletion and amortization of $1.84 billion and $1.60 billion, respectively, equity in earnings of unconsolidated affiliates of $228 million and $205 million, respectively, inventory valuation adjustments of $38 million and $203 million, respectively, deferred income taxes of $120 million and $139 million, respectively, and unit-based compensation expense of $76 million and $46 million, respectively.

Cash paid for interest, net of interest capitalized, was $1.41 billion and $1.43 billion for the nine months ended September 30, 2017 and 2016, respectively.

Capitalized interest was $177 million and $148 million for the nine months ended September 30, 2017 and 2016, respectively.

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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.

Nine months ended September 30,2017 compared to nine months ended September 30,2016. Cash used in investing activities during 2017 was $4.76 billion as compared to cash used in investing activities $6.08 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 $6.10 billion. This compares to total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2016 of $5.88 billion. During the nine months ended September 30, 2017, we had proceeds from transactions of $1.4 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.

Nine months ended September 30,2017 compared to nine months ended September 30,2016. Cash used in financing activities during 2017 was $1.30 billion as compared to cash provided by financing activities of $3.92 billion for 2016. In 2017, ETE received $2.20 billion in net proceeds from offerings of ETE common units and subsidiary common units as compared to $2.10 billion in 2016. In 2016, Sunoco Logistics received $1.31 billion in net proceeds from offerings of their common units. During 2017, we had a consolidated net increase in our debt level of $1.40 billion as compared to a net increase of $4.33 billion for 2016. In 2017, we paid net proceeds on affiliates notes in the amount of $255 million. We have paid distributions of $752 million and $780 million to our partners in 2017 and in 2016, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $2.16 billion and $2.03 billion in 2017 and 2016, respectively.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	September 30, 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	1,191			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	7,600			5,350
Transwestern Senior Notes	575			657
Sunoco LP Senior Notes, Term Loan and lease-related obligation	3,581			3,561
Credit Facilities and Commercial Paper:
ETLP $3.75 billion Revolving Credit Facility due November 2019 (1)	2,056			2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 (2)	35			1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017 (3)	—			630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019	644			1,000
Bakken Term Note	2,500			1,100
PennTex $275 million Revolving Credit Facility due December 2019	—			168
Other Long-Term Debt	5			31
Unamortized premiums and fair value adjustments, net	65			101
Deferred debt issuance costs	(268		)	(257		)
Total	45,211			43,802
Less: Current maturities of long-term debt	716			1,194
Long-term debt and notes payable, less current maturities	$	44,495		$	42,608

⁽¹⁾  Includes $2.06 billion and $777 million of commercial paper outstanding at September 30, 2017 and December 31, 2016, respectively.

⁽²⁾  Includes $50 million of commercial paper outstanding at December 31, 2016.

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

Senior Notes and Term Loan

Energy Transfer Equity, L.P. Senior Notes Offering 

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.

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.

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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 ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, 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 27.5 million common units representing limited partner interests in 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 ETP. 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.

On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.

In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.

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 September 30, 2017, the balance on the term loan was $1.24 billion.

ETP Senior Notes Redemption

In October 2017, ETP redeemed all of the outstanding$500 millionaggregate principal amount of ETLP’s6.50%senior notes due July 2021 and all of the outstanding$700 millionaggregate principal amount of ETLP’s5.50%senior notes due April 2023.The aggregate amount paid to redeem these notes, including call premiums, was approximately$1.23 billion.

ETP Senior Notes Offering

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued$750 millionaggregate principal amount of4.00%senior notes due 2027 and$1.50 billionaggregate principal amount of5.40%senior notes due 2047. The$2.22 billionnet proceeds from the offering were used to redeem all of the$500 millionaggregate principal amount of ETLP’s6.5%senior notes due 2021, to repay borrowings outstanding under the Sunoco LogisticsCredit Facility (described below) and for general partnership purposes.

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

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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 September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.

ETLP Credit Facility

The ETLP Credit Facility allows for borrowings of up to$3.75 billionand matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the$3.75 billionETLP Credit Facility.As ofSeptember 30, 2017, the ETLP Credit Facility had$2.06 billionof outstanding borrowings, all of which was commercial paper.

Sunoco Logistics Credit Facilities

ETP maintains the Sunoco Logistics$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 ofSeptember 30, 2017, the Sunoco Logistics Credit Facility had$35 millionof outstanding borrowings.

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

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 September 30, 2017, the Sunoco LP credit facility had $644 million of outstanding borrowings and $19 million in standby letters of credit. The unused availability on the revolver at September 30, 2017 was $847 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 provides substantially all of the remaining capital necessary to complete the projects. As ofSeptember 30, 2017, $2.5 billionwas outstanding under this credit facility.

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”).In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

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 September 30, 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

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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
June 30, 2017 (1)	August 7, 2017	August 21, 2017	0.2850
September 30, 2017	November 7, 2017	November 20, 2017	0.2950

⁽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 9, ETE Series A Convertible 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
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 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):

	Nine Months Ended September 30,
	2017		2016
Limited Partners	$	757	$	721
General Partner interest	2		2
Total Parent Company distributions	$	759	$	723

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 Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to 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 ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

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	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:

	Nine Months Ended September 30,
	2017			2016
Distributions from ETP:
Limited Partner interests	$	45		$	8
Class H Units	—			263
General Partner interest	12			24
IDRs	1,204			1,012
IDR relinquishments net of Class I Unit distributions	(482		)	(271		)
Total distributions from ETP	779			1,036
Distributions from Sunoco LP
Limited Partner interests	6			6
IDRs	63			60
Series A Preferred	15			—
Total distributions from Sunoco LP	84			66
Total distributions received from subsidiaries	863			1,102

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

	Total Year
2017 (remainder)	$	173
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.

Cash Distributions Paid by ETP

Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership, which was Sunoco Logistics’ limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP's business. ETP will

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make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

If cash distributions exceed$0.0833per unit in a quarter, the general partner receives increasing percentages, up to50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

The following table shows the target distribution levels and distribution "splits" between the general partner and the holders of ETP common units:

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

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

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

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

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 15, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 14, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650

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):

	Nine Months Ended September 30,
	2017			2016
	ETP			Energy Transfer Partners, L.P.			Sunoco Logistics
Limited Partners:
Common Units held by public	$	1,794		$	1,607		$	353
Common Units held by ETP	—			—			100
Common Units held by ETE	45			8			—
Class H Units held by ETE	—			263			—
General Partner interest	12			24			11
Incentive distributions held by ETE	1,204			1,012			289
IDR relinquishments	(482		)	(271		)	(8		)
Total distributions declared to partners	$	2,573		$	2,643		$	745

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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
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 2017	0.8255

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):

	Nine Months Ended September 30,
	2017		2016
Limited Partners:
Common units held by public	$	133	$	122
Common and subordinated units held by ETP	150		107
Common and subordinated units held by ETE	6		6
General Partner interest and Incentive distributions	63		60
Series A Preferred	15		—
Total distributions declared	$	367	$	295

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The Partnership’s critical accounting policies have not changed subsequent to those reported in Exhibit 99.1 to its Form 8-K filed on October 2, 2017. The following information is provided to supplement those disclosures specifically related to impairment of long-lived assets and goodwill.

Impairment of Long-Lived Assets and Goodwill.  During the three months ended June 30, 2017, Sunoco LP announced the sale of a majority of the assets in its retail reporting unit. Sunoco LP’s retail reporting unit includes the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, management allocated a portion of the goodwill balance previously included in the Sunoco LP retail reporting unit to assets held for sale based on the relative fair values of the business to be disposed of and the portion of the reporting unit that will be retained in accordance with ASC 350-20-40-3. The amount of goodwill allocated to assets held for sale was approximately $1.6 billion, and the amount of goodwill allocated to the remainder of the retail reporting unit, which is comprised of Sunoco LP’s ethanol plant, credit card processing services and franchise royalties, was approximately $188 million.

Once the retail reporting unit’s goodwill was allocated between assets held for sale and continuing operations, management performed goodwill impairment tests on both reporting units to which the goodwill balances were allocated. No goodwill impairment was identified for the $188 million goodwill balance that remained in the retail reporting unit. The result of the impairment test of the goodwill included within the assets held for sale initially indicated an impairment charge of $320 million, which was recognized during the three months ended June 30, 2017. Subsequent to June 30, 2017, management continued to evaluate the goodwill for impairment based on additional information on the fair value of the reporting unit, which resulted in an additional impairment of $44 million during the three months ended September 30, 2017. The key assumption in the impairment test for the goodwill balance classified as held for sale was the fair value of the disposal group, which was based on the assumed proceeds from the sale of those assets. The announced purchase and sale agreement includes the majority of the retail sites that have been classified as held for sale; thus, a key assumption in the goodwill impairment test was the assumed sales proceeds (less the related costs to sell) for the remainder of the sites, which represent approximately 15% of the total number of sites. Management is currently marketing the remaining sites for sale and utilized information from that sales process to develop the assumed sales proceeds for those sites. While management believes that the assumed sales proceeds for these remaining held-for-sale sites are

58

reasonable and likely to be obtained in a sale of those sites, an agreement has not been negotiated and therefore the ultimate outcome could be different than the assumption used in the impairment test. Subsequent to the impairment of goodwill included within the assets held for sale, no further impairments of any other assets held for sale were deemed necessary as the remaining carrying value of the disposal group approximated the assumed proceeds from the sale of those assets less the cost to sell.

For goodwill included in the Aloha and Wholesale reporting units, which goodwill balances total $112 million and $732 million, respectively, and which were not classified as held for sale, no impairments were deemed necessary during the three months ended June 30, 2017. Management does not believe that the goodwill associated with either of these reporting units or the remaining goodwill of $188 million within the retail reporting unit is at significant risk of impairment, and the goodwill will continue to be subjected to annual goodwill impairment testing on October 1.

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.

59

	September 30, 2017							December 31, 2016
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,297,500		$	—		$	—	(682,500	)	$	—		$	—
Basis Swaps IFERC/NYMEX (1)	(15,810,000	)	(4		)	—		2,242,500		(1		)	—
Options – Puts	13,000,000		—			—		—		—			—
Power (Megawatt):
Forwards	665,040		1			2		391,880		(1		)	1
Futures	(213,840	)	—			1		109,564		—			—
Options — Puts	(280,800	)	1			2		(50,400	)	—			—
Options — Calls	545,600		—			1		186,400		1			—
Crude (Bbls):
Futures	(160,000	)	1			1		(617,000	)	(4		)	6
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	67,500		(3		)	2		10,750,000		2			—
Swing Swaps IFERC	91,897,500		(2		)	—		(5,662,500	)	(1		)	1
Fixed Swaps/Futures	(20,220,000	)	1			7		(52,652,500	)	(27		)	19
Forward Physical Contracts	(140,937,993	)	3			43		(22,492,489	)	1			—
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(8,744,200	)	(48		)	80		(5,786,627	)	(40		)	35
Refined Products (Bbls) — Futures	(1,947,000	)	1			19		(3,144,000	)	(21		)	18
Corn (Bushels) — Futures	650,000		—			—		1,580,000		—			1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2			—		(36,370,000	)	2			1
Fixed Swaps/Futures	(41,102,500	)	5			12		(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 September 30, 2017, we and our subsidiaries had $10.47 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $105 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

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

		Notional Amount Outstanding
Term	Type(1)	September 30, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

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

⁽²⁾  Represents the effective date. These forward-starting swaps have 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 $237 million as of September 30, 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 $19 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 September 30, 2017 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal controls, 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 September 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2016 and Note 11 – 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 September 30, 2017.

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

Mont Belvieu received a Notice of Enforcement (“NOE”) with an Agreed Order from the Texas Commission on Environmental Quality and has a pending settlement for$0.01 million.  The NOE was for the two violations.

Energy Transfer Company Field Services, LLC received a settlement agreement and a stipulated final compliance order from the New Mexico Environmental Department (“NMED”) on October 12, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. This order is a combination of Notice of Violation REG-0569-1402-R1 and Notice of Violation REG-0569-1601. The alleged violations occurred during the periods of March 24, 2014 through September 30, 2014 and September 1, 2016 through December 31, 2016.The settlement includes a civil penalty in the amount of$0.4 millionand a supplement environmental project in the amount of$0.8 million.

Energy Transfer Company Field Services, LLC received a settlement offer from the NMED on June 6, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. The alleged violation occurred during the period of January 1, 2017 through September 11, 2017. The NMED is offering to settle the violations with a civil penalty of$0.6 million.

On July 14, 2017, Sunoco LP’s subsidiary Aloha Petroleum, Ltd. (“Aloha”) received a Notice of Violation and Order (“NOVO”) from the Hawaii Department of Health (“DOH”) relating to alleged leak detection and reporting deficiencies at Aloha’s AIM Diamond Head facility in Honolulu, Hawaii with proposed civil penalties of $0.2 million. Aloha is in discussions with the DOH regarding the NOVO. The timing or outcome of this matter cannot reasonably be determined at this time however, the Partnership does not expect there to be a material impact on our business or results of operations.

ITEM 1A. RISK FACTORS

There have been no material changes from the 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 or from the risk factors described in “Part II — Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

ITEM 6. EXHIBITS

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

Exhibit Number	Description
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.

62

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:	November 7, 2017	By:	/s/ Thomas E. Long
			Thomas E. Long
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)

63

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)

	Nine months ended
	September 30, 2017
Fixed Charges:
Interest expense, net	$	1,493
Capitalized interest	177
Interest charges included in rental expense	9
Total fixed charges	1,679
Earnings:
Loss before income tax expense and noncontrolling interest	1,378
Less: equity in earnings of unconsolidated affiliates	228
Total earnings	1,150
Add:
Fixed charges	1,679
Amortization of capitalized interest	15
Distributed income of equity investees	211
Less:
Interest capitalized	(177		)
Income available for fixed charges	$	2,878
Ratio of earnings to fixed charges	1.71

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

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

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

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

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

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

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

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

Date: November 7, 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. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

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

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

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

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

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

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

Date: November 7, 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 September 30, 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: November 7, 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 September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Long, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

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

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

Date: November 7, 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	9 Months Ended
	Sep. 30, 2017	Nov. 03, 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	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,079,185,030

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
ASSETS
Cash and cash equivalents	$ 469	$ 463
Accounts receivable, net	3,551	3,557
Accounts receivable from related companies	90	47
Inventories	1,957	2,103
Derivative assets	42	21
Other current assets	433	503
Current assets held for sale	4,147	291
Total current assets	10,689	6,985
Property, plant and equipment	68,730	61,158
Accumulated depreciation and depletion	(9,463)	(7,905)
Property, Plant and Equipment, Net	59,267	53,253
Advances to and investments in unconsolidated affiliates	3,177	3,040
Other non-current assets, net	891	816
Intangible assets, net	6,195	5,489
Goodwill	5,161	5,170
Disposal Group, Including Discontinued Operation, Assets, Noncurrent	0	4,258
Total assets	85,380	79,011
LIABILITIES AND EQUITY
Accounts payable	3,994	3,502
Accounts payable to related companies	46	42
Derivative liabilities	129	172
Accrued and other current liabilities	2,881	2,367
Current maturities of long-term debt	716	1,194
Liabilities associated with assets held for sale	81	0
Total current liabilities	7,847	7,277
Long-term debt, less current maturities	44,495	42,608
Long-term notes payable – related companies	0	250
Non-current derivative liabilities	132	76
Deferred income taxes	5,027	5,112
Other non-current liabilities	1,218	1,055
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent	0	68
Commitments and contingencies
Preferred units of subsidiary	0	33
Redeemable noncontrolling interests	21	15
EQUITY:
General Partner	(3)	(3)
Limited Partners:
Common Unitholders	(1,566)	(1,871)
Series A Convertible Preferred Units	377	180
Total partners’ deficit	(1,192)	(1,694)
Noncontrolling interest	27,832	24,211
Total equity	26,640	22,517
Total liabilities and equity	$ 85,380	$ 79,011

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Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES
Natural gas sales	$ 1,098	$ 1,070	$ 3,132	$ 2,603
NGL sales	1,749	1,249	4,782	3,339
Crude sales	2,273	1,649	6,751	4,572
Gathering, transportation and other fees	1,068	1,028	3,244	3,118
Refined product sales	2,706	2,243	7,928	6,249
Other	580	466	1,800	1,346
Total revenues	9,474	7,705	27,637	21,227
COSTS AND EXPENSES
Cost of products sold	7,078	5,776	21,028	15,430
Operating expenses	636	526	1,779	1,540
Depreciation, depletion and amortization	632	548	1,840	1,596
Selling, general and administrative	142	209	484	515
Total costs and expenses	8,488	7,059	25,131	19,081
OPERATING INCOME	986	646	2,506	2,146
OTHER INCOME (EXPENSE)
Interest expense, net	(505)	(474)	(1,471)	(1,336)
Equity in earnings of unconsolidated affiliates	92	49	228	205
Impairment of investment in an unconsolidated affiliate	0	(308)	0	(308)
Losses on extinguishments of debt	0	0	(25)	0
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Other, net	76	55	168	98
INCOME (LOSS) BEFORE INCOME TAX BENEFIT	641	(60)	1,378	626
Income tax benefit	(157)	(89)	(97)	(151)
INCOME FROM CONTINUING OPERATIONS	798	29	1,475	777
Income (loss) from discontinued operations, net of income taxes	6	12	(264)	24
NET INCOME	804	41	1,211	801
Less: Net income (loss) attributable to noncontrolling interest	552	(168)	508	39
NET INCOME ATTRIBUTABLE TO PARTNERS	252	209	703	762
General Partner’s interest in net income	1	0	2	2
Convertible Unitholders’ interest in income	11	2	25	3
Limited Partners’ interest in net income	$ 240	$ 207	$ 676	$ 757
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$ 0.22	$ 0.20	$ 0.63	$ 0.72
Diluted	$ 0.22	$ 0.19	$ 0.61	$ 0.71

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Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 804	$ 41	$ 1,211	$ 801
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities	2	0	5	5
Actuarial gain (loss) relating to pension and other postretirement benefit plans	5	0	2	(3)
Foreign currency translation adjustments	0	0	0	(1)
Change in other comprehensive income (loss) from unconsolidated affiliates	0	2	(1)	(9)
Other comprehensive income (loss), net of tax	7	2	6	(8)
Comprehensive income	811	43	1,217	793
Less: Comprehensive income (loss) attributable to noncontrolling interest	559	(166)	514	31
Comprehensive income attributable to partners	$ 252	$ 209	$ 703	$ 762

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Consolidated Statement Of Equity - 9 months ended Sep. 30, 2017 - USD ($) $ in Millions	Total	General Partner	Common Unitholders	Series A Convertible Preferred Units [Member]	Noncontrolling Interest
Balance, December 31, 2016 at Dec. 31, 2016	$ 22,517	$ (3)	$ (1,871)	$ 180	$ 24,211
Distributions to partners	(752)	(2)	(750)	0	0
Distributions to noncontrolling interest	(2,180)	0	0	0	(2,180)
Distributions reinvested	0	0	(173)	173	0
Subsidiary units issued	1,635	0	(56)	(1)	1,692
Issuance of common units	568	0	568	0	0
Capital contributions received from noncontrolling interests	1,907	0	0	0	1,907
PennTex unit acquisition	(280)	0	(2)	0	(278)
Non-cash compensation expense, net of units tendered by employees for tax withholdings	69	0	0	0	69
Sale of Bakken Pipeline interest	2,000	0	42	0	1,958
Other comprehensive income, net of tax	6	0	0	0	6
Other, net	(61)	0	0	0	(61)
Net income	1,211	2	676	25	508
Balance, September 30, 2017 at Sep. 30, 2017	$ 26,640	$ (3)	$ (1,566)	$ 377	$ 27,832

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Consolidated Statements Of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
OPERATING ACTIVITIES
Net income	$ 1,211	$ 801
Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in an unconsolidated affiliate	0	308
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	264	(24)
Depreciation, depletion and amortization	1,840	1,596
Deferred income taxes	(120)	(139)
Unit-based compensation expense	76	46
Losses on extinguishments of debt	(25)	0
Inventory valuation adjustments	(38)	(203)
Equity in earnings of unconsolidated affiliates	(228)	(205)
Distributions from unconsolidated affiliates	211	190
Other	(134)	(197)
Net change in operating assets and liabilities, net of effects of acquisition	222	48
Net cash provided by operating activities	3,304	2,221
INVESTING ACTIVITIES
Cash received from Bakken Pipeline Transaction	2,000	0
Cash paid for acquisition of a noncontrolling interest	(280)	0
Cash paid for acquisitions, net of cash received	(293)	(330)
Capital expenditures, excluding allowance for equity funds used during construction	(6,102)	(5,877)
Contributions to unconsolidated affiliate	230	47
Distributions from unconsolidated affiliates in excess of cumulative earnings	115	112
Other	30	58
Net cash used in investing activities	(4,760)	(6,084)
FINANCING ACTIVITIES
Proceeds from borrowings	23,988	18,288
Repayments of long-term debt	(22,586)	(13,955)
Proceeds from Related Party Debt	0	1,606
Repayments of Related Party Debt	(255)	(1,607)
Subsidiary units issued for cash	1,635	2,097
Proceeds from Issuance of Common Limited Partners Units	568	0
Distributions to partners	(752)	(780)
Distributions to noncontrolling interest	(2,156)	(2,027)
Capital contributions received from noncontrolling interest	919	187
Other	(58)	110
Net cash provided by financing activities	1,303	3,919
Cash Provided by (Used in) Operating Activities, Discontinued Operations	245	168
Cash Provided by (Used in) Investing Activities, Discontinued Operations	(82)	(359)
Increase (Decrease) in Assets Held-for-sale	(4)	12
Net Cash Provided by (Used in) Discontinued Operations	159	(179)
Increase (decrease) in cash and cash equivalents	6	(123)
Cash and cash equivalents, beginning of period	463	581
Cash and cash equivalents, end of period	$ 469	$ 458

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Operations And Organization

9 Months Ended

Sep. 30, 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. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P.Under the terms of the transaction, the unitholders received1.5common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately832 millionSunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.

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

At the time of theSunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” 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 “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;

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

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

The consolidated financial statements of 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 15 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 for the year ended December 31, 2016 included as Exhibit 99.1 to our Form 8-K filed on October 2, 2017. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliate. Additionally, there were other prior period amounts reclassified to conform to the 2017 presentation. Other than the reclassification of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations, 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

ASU 2014-09

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard.

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) 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.

We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of ETP’s reportable segments as well as the accounting for certain processing contracts in ETP’s midstream operations. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.

We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income.

We have substantially completed a detailed review of revenue contracts representative of Sunoco LP’s business segments and their revenue streams; however, we continue to evaluate contract modifications and new contracts that have been or will be entered prior to the adoption date. As a result of the evaluation performed to date, we have determined that the timing and/or amount of revenue that Sunoco LP recognizes on certain contracts will be impacted by the adoption of the new standard; however, we are quantifying these impacts and cannot currently conclude whether or not they would be material to the financial statements.

We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. 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.

ASU 2016-02

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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.

ASU 2016-09

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.

ASU 2016-16

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.

ASU 2016-17

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.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. Sunoco LP early adopted ASC No. 2017-04 during its interim goodwill impairment test in the second quarter of 2017. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

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Acquisitions

9 Months Ended

Sep. 30, 2017

ACQUISITIONS AND DIVESTITURE [Abstract]

Acquisitions

ACQUISITIONS AND DIVESTURES

Rover Contribution Agreement

In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.  The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.

Permian Express Partners

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

In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP 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 ETP. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

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 approximately1,112 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 “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.

With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the 7-Eleven purchase agreement.

Sunoco LP Real Estate Sale

In January 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets 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. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketed by the third-party brokerage firm.

The assets under the asset purchase agreement, the 208 Stripes sites and the real estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”).

The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.

The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:

	September 30, 2017		December 31, 2016
Carrying amount of assets classified as held for sale:
Cash and cash equivalents	$	24	$	20
Inventories	183		188
Other current assets	91		83
Property, plant and equipment, net	2,132		2,185
Goodwill	1,216		1,568
Intangible assets, net	499		503
Other non-current assets, net	2		2
Total assets classified as held for sale in the Consolidated Balance Sheet	$	4,147	$	4,549
Carrying amount of liabilities classified as held for sale:
Other current and non-current liabilities	81		68
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	81	$	68

The results of operations associated with discontinued operations are presented in the following table:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
REVENUES	$	2,312	$	1,970	$	6,580		$	5,474
COSTS AND EXPENSES
Cost of products sold	1,927		1,585		5,478			4,445
Operating expenses	236		250		727			727
Depreciation, depletion and amortization	5		47		68			149
Selling, general and administrative	57		37		122			74
Total costs and expenses	2,225		1,919		6,395			5,395
OPERATING INCOME	87		51		185			79
Interest expense, net	13		7		22			22
Other, net	38		1		367			4
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)	36		43		(204		)	53
Income tax expense	30		31		60			29
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	6	$	12	$	(264	)	$	24
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE	$	—	$	—	$	(9	)	$	—

In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $320 million recognized in the three months ended June 30, 2017 and $44 million recognized in the three months ended September 30, 2017.

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Cash And Cash Equivalents

9 Months Ended

Sep. 30, 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 be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Non-cash investing activities were as follows:

	Nine Months Ended September 30,
	2017			2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,237		$	1,001
Losses from subsidiary common unit issuances, net	(57		)	(3		)
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988		$	—

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Inventories (Notes)

9 Months Ended

Sep. 30, 2017

Inventory, Net [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:

	September 30, 2017		December 31, 2016
Natural gas and NGLs	$	609	$	699
Crude oil	696		683
Refined products	413		483
Other	239		238
Total inventories	$	1,957	$	2,103

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

9 Months Ended

Sep. 30, 2017

Fair Value Measurements [Abstract]

Fair Value Measurements

FAIR VALUE MEASURES

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2017 were $47.21 billion and $45.21 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations were $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 and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the nine months endedSeptember 30, 2017, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 based on inputs used to derive their fair values:

				Fair Value Measurements at September 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—
Swing Swaps IFERC	2			—			2
Fixed Swaps/Futures	28			28			—
Forward Physical Swaps	3			—			3
Power:
Forwards	11			—			11
Futures	1			1			—
Options — Puts	1			1			—
Natural Gas Liquids – Forwards/Swaps	213			213			—
Refined Products — Futures	4			4			—
Crude – Futures	2			2			—
Total commodity derivatives	281			265			16
Total assets	$	281		$	265		$	16
Liabilities:
Interest rate derivatives	$	(210	)	$	—		$	(210	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(22		)	(22		)	—
Swing Swaps IFERC	(3		)	(1		)	(2		)
Fixed Swaps/Futures	(22		)	(22		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(9		)	—			(9		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(261		)	(261		)	—
Refined Products — Futures	(3		)	(3		)	—
Crude — Futures	(1		)	(1		)	—
Total commodity derivatives	(323		)	(311		)	(12		)
Total liabilities	$	(533	)	$	(311	)	$	(222	)

				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 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

9 Months Ended

Sep. 30, 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 September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
Income from continuing operations	$	798	$	29		$	1,475		$	777
Less: Income (loss) from continuing operations attributable to noncontrolling interest	546		(180		)	763			15
Income from continuing operations, net of noncontrolling interest	252		209			712			762
Less: General Partner’s interest in income	1		—			2			2
Less: Convertible Unitholders’ interest in income	11		2			25			3
Income from continuing operations available to Limited Partners	$	240	$	207		$	685		$	757
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,079.1		1,045.5			1,077.9			1,045.0
Basic income from continuing operations per Limited Partner unit	$	0.22	$	0.20		$	0.64		$	0.72
Basic loss from discontinued operations per Limited Partner unit	$	0.00	$	0.00		$	(0.01	)	$	0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	240	$	207		$	685		$	757
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	10		2			25			3
Diluted income from continuing operations available to Limited Partners	$	250	$	209		$	710		$	760
Weighted average limited partner units	1,079.1		1,045.5			1,077.9			1,045.0
Dilutive effect of unconverted unit awards and Convertible Units	69.2		55.2			69.4			26.3
Diluted weighted average limited partner units	1,148.3		1,100.7			1,147.3			1,071.3
Diluted income from continuing operations per Limited Partner unit	$	0.22	$	0.19		$	0.62		$	0.71
Diluted loss from discontinued operations per Limited Partner unit	$	0.00	$	0.00		$	(0.01	)	$	0.00

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Debt Obligations

9 Months Ended

Sep. 30, 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.

Energy Transfer Equity, L.P. Senior Notes Offering 

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.

The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.

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 ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, 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 27.5 million common units representing limited partner interests in 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 ETP. The Term Loan Facility 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.

On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.

In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.

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 September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.

Subsidiary Indebtedness

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 September 30, 2017, the balance on the term loan was $1.24 billion.

ETP Senior Notes Redemption

In October 2017, ETP redeemed all of the outstanding$500 millionaggregate principal amount of ETLP’s6.50%senior notes due July 2021 and all of the outstanding$700 millionaggregate principal amount of ETLP’s5.50%senior notes due April 2023.The aggregate amount paid to redeem these notes, including call premiums, was approximately$1.23 billion.

ETP Senior Notes Offering

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued$750 millionaggregate principal amount of4.00%senior notes due 2027 and$1.50 billionaggregate principal amount of5.40%senior notes due 2047. The$2.22 billionnet proceeds from the offering were used to redeem all of the$500 millionaggregate principal amount of ETLP’s6.5%senior notes due 2021, to repay borrowings outstanding under the Sunoco LogisticsCredit Facility (described below) and for general partnership purposes.

The senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal is payable upon maturity. Interest on the senior notes is paid semi-annually. The senior notes are guaranteed by ETP on a senior unsecured basis as long as it guarantees any of Sunoco Logistics Partners Operations L.P.’s other long-term debt.As a result of the parent guarantee, the senior notes will rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any subordinated debt ETP may incur.  

ETLP Credit Facility

The ETLP Credit Facility allows for borrowings of up to$3.75 billionand matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the$3.75 billionETLP Credit Facility.As ofSeptember 30, 2017, the ETLP Credit Facility had$2.06 billionof outstanding borrowings, all of which was commercial paper.

Sunoco Logistics Credit Facilities

ETP maintains the Sunoco Logistics$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 ofSeptember 30, 2017, the Sunoco Logistics Credit Facility had$35 millionof outstanding borrowings.

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

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 September 30, 2017, the Sunoco LP credit facility had $644 million of outstanding borrowings and $9 million in standby letters of credit. The unused availability on the revolver at September 30, 2017 was $847 million.

On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Agreement with the lenders party thereto and Bank of America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.

Bakken Credit Facility

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

PennTex Revolving Credit Facility

PennTex previously maintained a$275 millionrevolving credit commitment (the “PennTex Revolving Credit Facility”).In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

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 September 30, 2017.

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Redeemable Preferred Units (Notes)

9 Months Ended

Sep. 30, 2017

Redeemable Preferred Units [Abstract]

Preferred Units [Text Block]

PREFERRED UNITS

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

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Equity

9 Months Ended

Sep. 30, 2017

Partners' Capital Notes [Abstract]

Equity

EQUITY

ETE

The changes in ETE common units and Convertible Units during the nine months ended September 30,2017 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 September 30, 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 nine months endedSeptember 30, 2017.

Series A Convertible Preferred Units

As of September 30, 2017, the Partnership had 329.3 million Series A Convertible Preferred Units outstanding with a carrying value of $377 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 23.7 million newly issued ETP common units for approximately $568 million.

Repurchase Program

During the nine months endedSeptember 30, 2017, ETE did not repurchase any ETE common units under its current buyback program. As of September 30, 2017, $936 million remained available to repurchase under the current program.

Subsidiary Equity 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 nine months endedSeptember 30, 2017, we recognized decreases in partners’ capital of $57 million.

ETP Common Unit Transaction

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion. During thenine months ended September 30,2017, ETP received proceeds of $498 million, net of$5 millionof commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan. During the nine months endedSeptember 30, 2017, distributions of$106 millionwere reinvested under the distribution reinvestment plan.

ETP August 2017 Units Offering

In August 2017, ETP issued54 millionETP common unitsin an underwritten public offering. Net proceeds of$997 millionfrom the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

Bakken Equity Sale

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100%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 and ETCO.The remaining25%of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

PennTex Tender Offer and Limited Call Right Exercise

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

Sunoco LP Common Unit Transactions

During the nine months ended September 30,2017, 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 September 30, 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.

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
June 30, 2017 (1)	August 7, 2017	August 21, 2017	$	0.2850
September 30, 2017 (1)	November 7, 2017	November 20, 2017	0.2950

⁽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
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 2017	0.1100

ETP Quarterly Distributions of Available Cash

Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP's business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

If cash distributions exceed$0.0833per unit in a quarter, the general partner receives increasing percentages, up to50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

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

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

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 15, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 14, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650

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

	Total Year
2017 (remainder)	$	173
2018	153
2019	128
Each year beyond 2019	33

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
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 2017	0.8255

Accumulated Other Comprehensive Income

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

	September 30, 2017			December 31, 2016
Available-for-sale securities	$	7		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	9			7
Investments in unconsolidated affiliates, net	3			4
Subtotal	14			8
Amounts attributable to noncontrolling interest	(14		)	(8		)
Total AOCI, net of tax	$	—		$	—

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Income Taxes (Notes)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately$68 million during the periods presented. The remainder of the increase in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. For the three and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

9 Months Ended

Sep. 30, 2017

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012,ETLP (formerly Energy Transfer Partners, L.P.)agreed to provide contingent residual support of$1.55 billionof intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETLP under the contingent residual support agreement. In February 2017, AmeriGas repurchased a portion of its7.00%senior notes. The remaining outstanding7.00%senior notes were repurchased in May 2017, and ETLP no longer provides contingent residual support for any AmeriGas notes.

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 2047.  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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Rental expense	$	42		$	31		$	106		$	94
Less: Sublease rental income	(6		)	(6		)	(19		)	(18		)
Rental expense, net	$	36		$	25		$	87		$	76

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

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

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.

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

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

On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete this additional work by April 2018. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relating to its remand order.

While we believe that the pending lawsuits are unlikely to block operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.

MTBE Litigation

Sunoco, Inc. and/or Sunoco, Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically governmental authorities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As ofSeptember 30, 2017, Sunoco, Inc. is a defendant insixcases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, Rhode Island, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action.Fourof these cases are venued in a multidistrict litigation proceeding in a New York federal court.

Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The court approved the Judicial Consent Order on October 10, 2017.

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).

The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Merger Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. A hearing on these motions is currently set for January 9, 2018.

The Regency Merger Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Merger Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.

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

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of$319 millionin compensatory damages and$595 millionin disgorgement to ETP.  The jury also found that ETP owed Enterprise approximately$1 millionunder a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP$536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP intends to file a petition for review with the Texas Supreme Court.

Sunoco Logistics Merger Litigation

Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits have been voluntarily dismissed. The five remaining lawsuits have been consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”).The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”).The ETP Unitholder Plaintiffs seek rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees.

The ETP-SXL Defendants cannot predict the outcome of the Sunoco Logistics Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing, nor can the ETP-SXL Defendants predict the amount of time and expense that will be required to resolve the Sunoco Logistics Merger Litigation. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Sunoco Logistics Merger.

Litigation Filed By or Against Williams

On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams 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 Williams Litigation. The counterclaim asserts in general that Williams 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 Williams’ 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 a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.

On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that 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 concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams 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.

ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams 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, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. 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 a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware WMB Litigation 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 Williams’ requests for injunctive relief. The Court did not reach Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.

Williams filed an amended complaint on September 16, 2016 and sought 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 Defendants breached an additional representation and warranty in the Merger Agreement.

Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought 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 Defendants’ amended counterclaims and to strike certain of 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 March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

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 (collectively, the “Issuance Defendants”) 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 (the “Issuance Litigation”). 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.

On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.

The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.

The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance.

Litigation filed by BP Products

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

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.

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

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

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 September 30, 2017 and December 31, 2016, accruals of approximately $68 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations.  As new information becomes available, our estimates may change.  The impact of these changes may have a significant effect on our results of operations in a single period.

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

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

The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of approximately $2.3 millionin connection with the alleged violations and is seeking certain corrective actions. ETP is working with Ohio EPA to resolve the matter. The timing or outcome of this matter cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at27sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.

On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  On August 1, 2017 the EHB lifted the order as to two drill locations.  On August 3, 2017, the EHB lifted the order as to 14 additional locations.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting.  On August 7, 2017 a final settlement was reached.  A stipulated order has been submitted to the EHB Judge with respect to the settlement.  The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.

In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.

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

Environmental Matters

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

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

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

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

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

• Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.

• Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

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

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

• Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As ofSeptember 30, 2017, Sunoco, Inc. had been named as a PRP at approximately44identified 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.

	September 30, 2017		December 31, 2016
Current	$	42	$	31
Non-current	302		318
Total environmental liabilities	$	344	$	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 September 30,2017 and 2016, the Partnership recorded $7 million and $12 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2017 and 2016, the Partnership recorded $22 million and $31 million, respectively.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of$200,000to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

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Derivative Assets And Liabilities

9 Months Ended

Sep. 30, 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 ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s 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 ETP’s midstream segment whereby its 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 ETP’s NGL and refined products transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

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

We use 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 ETP’s 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 ETP’s 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 ETP’s 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:

	September 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,297,500		2017-2018	(682,500	)	2017
Basis Swaps IFERC/NYMEX (1)	(15,810,000	)	2017-2019	2,242,500		2017
Options – Puts	13,000,000		2018	—		—
Power (Megawatt):
Forwards	665,040		2017-2018	391,880		2017-2018
Futures	(213,840	)	2017-2018	109,564		2017-2018
Options — Puts	(280,800	)	2017-2018	(50,400	)	2017
Options — Calls	545,600		2017-2018	186,400		2017
Crude (Bbls):
Futures	(160,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	67,500		2017-2020	10,750,000		2017-2018
Swing Swaps IFERC	91,897,500		2017-2019	(5,662,500	)	2017
Fixed Swaps/Futures	(20,220,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(140,937,993	)	2017-2018	(22,492,489	)	2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(8,744,200	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) — Futures	(1,947,000	)	2017-2018	(3,144,000	)	2017
Corn (Bushels) — Futures	650,000		2017-2018	1,580,000		2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(41,102,500	)	2017	(36,370,000	)	2017
Hedged Item — Inventory	41,102,500		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)	September 30, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

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

⁽²⁾  Represents the effective date. These forward-starting swaps have 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
	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	7	$	—	$	—		$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	222	$	338	$	(262	)	$	(416	)
Commodity derivatives	52		25		(61		)	(58		)
Interest rate derivatives	—		—		(210		)	(193		)
Embedded derivatives in the ETP Preferred Units	—		—		—			(1		)
	274		363		(533		)	(668		)
Total derivatives	$	281	$	363	$	(533	)	$	(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	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(210	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	52			25			(61		)	(58		)
Broker cleared derivative contracts	Other current assets	229			338			(262		)	(420		)
Total gross derivatives		281			363			(533		)	(672		)
Less offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(10		)	(4		)	10			4
Payments on margin deposit	Other current assets	(220		)	(338		)	220			338
Total net derivatives		$	51		$	21		$	(303	)	$	(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 September 30,					Nine Months Ended September 30,
		2017		2016			2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	2	$	(9	)	$	4	$	8
Total		$	2	$	(9	)	$	4	$	8

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading	Cost of products sold	$	(5	)	$	(7	)	$	21		$	(24	)
Commodity derivatives —Non-trading	Cost of products sold	(25		)	(16		)	(6		)	(61		)
Interest rate derivatives	Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Embedded derivatives	Other, net	—			8			1			4
Total		$	(38	)	$	(43	)	$	(12	)	$	(260	)

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Related Party Transactions

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

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

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 expired in 2016.

In addition, ETE recorded sales with affiliates of $105 million and $49 million during the three months endedSeptember 30, 2017 and 2016, respectively, and $201 million and $175 million during the nine months endedSeptember 30, 2017 and 2016, respectively.

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Reportable Segments

9 Months Ended

Sep. 30, 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.

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Investment in ETP	$	1,744		$	1,390		$	4,757		$	4,172
Investment in Sunoco LP	199			189			574			512
Investment in Lake Charles LNG	43			45			131			133
Corporate and Other	(3		)	(37		)	(25		)	(142		)
Adjustments and Eliminations	(74		)	(83		)	(211		)	(208		)
Total	1,909			1,504			5,226			4,467
Depreciation, depletion and amortization	(632		)	(548		)	(1,840		)	(1,596		)
Interest expense, net	(505		)	(474		)	(1,471		)	(1,336		)
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Non-cash unit-based compensation expense	(29		)	(23		)	(76		)	(46		)
Unrealized gains (losses) on commodity risk management activities	(76		)	(21		)	22			(105		)
Losses on extinguishments of debt	—			—			(25		)	—
Inventory valuation adjustments	141			35			38			203
Equity in earnings of unconsolidated affiliates	92			49			228			205
Adjusted EBITDA related to unconsolidated affiliates	(205		)	(157		)	(554		)	(503		)
Adjusted EBITDA related to discontinued operations	(92		)	(93		)	(253		)	(220		)
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Other, net	46			4			111			44
Income (loss) before income tax benefit	$	641		$	(60	)	$	1,378		$	626

	September 30, 2017			December 31, 2016
Assets:
Investment in ETP	$	77,011		$	70,191
Investment in Sunoco LP	8,307			8,701
Investment in Lake Charles LNG	1,611			1,508
Corporate and Other	620			711
Adjustments and Eliminations	(2,169		)	(2,100		)
Total assets	$	85,380		$	79,011

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Investment in ETP:
Revenues from external customers	$	6,876		$	5,488		$	20,168		$	15,167
Intersegment revenues	97			43			276			134
	6,973			5,531			20,444			15,301
Investment in Sunoco LP:
Revenues from external customers	2,549			2,167			7,321			5,912
Intersegment revenues	6			—			9			6
	2,555			2,167			7,330			5,918
Investment in Lake Charles LNG:
Revenues from external customers	49			50			148			148
Adjustments and Eliminations	(103		)	(43		)	(285		)	(140		)
Total revenues	$	9,474		$	7,705		$	27,637		$	21,227

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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Intrastate Transportation and Storage	$	729	$	583	$	2,196	$	1,457
Interstate Transportation and Storage	220		231		652		714
Midstream	665		582		1,863		1,799
NGL and refined products transportation and services	1,989		1,397		5,874		4,014
Crude oil transportation and services	2,714		1,856		7,749		5,146
All Other	656		882		2,110		2,171
Total revenues	6,973		5,531		20,444		15,301
Less: Intersegment revenues	97		43		276		134
Revenues from external customers	$	6,876	$	5,488	$	20,168	$	15,167

The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger.

Investment in Sunoco LP

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Retail operations	$	88	$	80	$	247	$	241
Wholesale operations	2,467		2,087		7,083		5,677
Total revenues	2,555		2,167		7,330		5,918
Less: Intersegment revenues	6		—		9		6
Revenues from external customers	$	2,549	$	2,167	$	7,321	$	5,912

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

9 Months Ended

Sep. 30, 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)

	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	2
Accounts receivable from related companies	64			55
Other current assets	2			—
Total current assets	66			57
Property, plant and equipment, net	27			36
Advances to and investments in unconsolidated affiliates	6,031			5,088
Intangible assets, net	—			1
Goodwill	9			9
Other non-current assets, net	17			10
Total assets	$	6,150		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	1
Accounts payable to related companies	—			22
Interest payable	79			66
Accrued and other current liabilities	3			3
Total current liabilities	82			92
Long-term debt, less current maturities	6,684			6,358
Long-term notes payable – related companies	574			443
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ capital:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,566		)	(1,871		)
Series A Convertible Preferred Units	377			180
Total partners’ deficit	(1,192		)	(1,694		)
Total liabilities and equity	$	6,150		$	5,201

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(3	)	$	(75	)	$	(25	)	$	(156	)
OTHER INCOME (EXPENSE):
Interest expense, net	(88		)	(81		)	(257		)	(244		)
Equity in earnings of unconsolidated affiliates	343			367			1,012			1,166
Losses on extinguishments of debt	—			—			(25		)	—
Other, net	—			(2		)	(2		)	(4		)
NET INCOME	252			209			703			762
General Partner’s interest in net income	1			—			2			2
Convertible Unitholders’ interest in income	11			2			25			3
Limited Partners’ interest in net income	$	240		$	207		$	676		$	757

⁽¹⁾  Prior periods include 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)

	Nine Months Ended September 30,
	2017			2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	620		$	718
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(861		)	(70		)
Capital expenditures	(1		)	(15		)
Contributions in aid of construction costs	7			—
Net cash used in investing activities	(855		)	(85		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,116			180
Principal payments on debt	(1,795		)	(155		)
Proceeds from affiliate	131			129
Distributions to partners	(752		)	(780		)
Units issued for cash	568			—
Debt issuance costs	(35		)	—
Net cash provided by (used in) financing activities	233			(626		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(2		)	7
CASH AND CASH EQUIVALENTS, beginning of period	2			1
CASH AND CASH EQUIVALENTS, end of period	$	—		$	8

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Operations And Organization Accounting policy (Policies)

9 Months Ended

Sep. 30, 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

ASU 2014-09

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application, of the cumulative effect of the retrospective application of the standard.

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) 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.

We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of ETP’s reportable segments as well as the accounting for certain processing contracts in ETP’s midstream operations. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.

We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income.

We have substantially completed a detailed review of revenue contracts representative of Sunoco LP’s business segments and their revenue streams; however, we continue to evaluate contract modifications and new contracts that have been or will be entered prior to the adoption date. As a result of the evaluation performed to date, we have determined that the timing and/or amount of revenue that Sunoco LP recognizes on certain contracts will be impacted by the adoption of the new standard; however, we are quantifying these impacts and cannot currently conclude whether or not they would be material to the financial statements.

We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. 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.

ASU 2016-02

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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.

ASU 2016-09

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.

ASU 2016-16

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.

ASU 2016-17

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.

ASU 2017-04

In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. Sunoco LP early adopted ASC No. 2017-04 during its interim goodwill impairment test in the second quarter of 2017. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

ASU 2017-12

In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2017

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations [Table Text Block]

The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:

	September 30, 2017		December 31, 2016
Carrying amount of assets classified as held for sale:
Cash and cash equivalents	$	24	$	20
Inventories	183		188
Other current assets	91		83
Property, plant and equipment, net	2,132		2,185
Goodwill	1,216		1,568
Intangible assets, net	499		503
Other non-current assets, net	2		2
Total assets classified as held for sale in the Consolidated Balance Sheet	$	4,147	$	4,549
Carrying amount of liabilities classified as held for sale:
Other current and non-current liabilities	81		68
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	81	$	68

The results of operations associated with discontinued operations are presented in the following table:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
REVENUES	$	2,312	$	1,970	$	6,580		$	5,474
COSTS AND EXPENSES
Cost of products sold	1,927		1,585		5,478			4,445
Operating expenses	236		250		727			727
Depreciation, depletion and amortization	5		47		68			149
Selling, general and administrative	57		37		122			74
Total costs and expenses	2,225		1,919		6,395			5,395
OPERATING INCOME	87		51		185			79
Interest expense, net	13		7		22			22
Other, net	38		1		367			4
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)	36		43		(204		)	53
Income tax expense	30		31		60			29
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	6	$	12	$	(264	)	$	24
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE	$	—	$	—	$	(9	)	$	—

In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $320 million recognized in the three months ended June 30, 2017 and $44 million recognized in the three months ended September 30, 2017.

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Cash And Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2017

Supplemental Cash Flow Information [Abstract]

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

Non-cash investing activities were as follows:

	Nine Months Ended September 30,
	2017			2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,237		$	1,001
Losses from subsidiary common unit issuances, net	(57		)	(3		)
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	988		$	—

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Inventories (Tables)

9 Months Ended

Sep. 30, 2017

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:

	September 30, 2017		December 31, 2016
Natural gas and NGLs	$	609	$	699
Crude oil	696		683
Refined products	413		483
Other	239		238
Total inventories	$	1,957	$	2,103

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2017 and December 31, 2016 based on inputs used to derive their fair values:

				Fair Value Measurements at September 30, 2017
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—
Swing Swaps IFERC	2			—			2
Fixed Swaps/Futures	28			28			—
Forward Physical Swaps	3			—			3
Power:
Forwards	11			—			11
Futures	1			1			—
Options — Puts	1			1			—
Natural Gas Liquids – Forwards/Swaps	213			213			—
Refined Products — Futures	4			4			—
Crude – Futures	2			2			—
Total commodity derivatives	281			265			16
Total assets	$	281		$	265		$	16
Liabilities:
Interest rate derivatives	$	(210	)	$	—		$	(210	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(22		)	(22		)	—
Swing Swaps IFERC	(3		)	(1		)	(2		)
Fixed Swaps/Futures	(22		)	(22		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power:
Forwards	(9		)	—			(9		)
Futures	(1		)	(1		)	—
Natural Gas Liquids – Forwards/Swaps	(261		)	(261		)	—
Refined Products — Futures	(3		)	(3		)	—
Crude — Futures	(1		)	(1		)	—
Total commodity derivatives	(323		)	(311		)	(12		)
Total liabilities	$	(533	)	$	(311	)	$	(222	)

				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 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)

9 Months Ended

Sep. 30, 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 September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
Income from continuing operations	$	798	$	29		$	1,475		$	777
Less: Income (loss) from continuing operations attributable to noncontrolling interest	546		(180		)	763			15
Income from continuing operations, net of noncontrolling interest	252		209			712			762
Less: General Partner’s interest in income	1		—			2			2
Less: Convertible Unitholders’ interest in income	11		2			25			3
Income from continuing operations available to Limited Partners	$	240	$	207		$	685		$	757
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,079.1		1,045.5			1,077.9			1,045.0
Basic income from continuing operations per Limited Partner unit	$	0.22	$	0.20		$	0.64		$	0.72
Basic loss from discontinued operations per Limited Partner unit	$	0.00	$	0.00		$	(0.01	)	$	0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	240	$	207		$	685		$	757
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	10		2			25			3
Diluted income from continuing operations available to Limited Partners	$	250	$	209		$	710		$	760
Weighted average limited partner units	1,079.1		1,045.5			1,077.9			1,045.0
Dilutive effect of unconverted unit awards and Convertible Units	69.2		55.2			69.4			26.3
Diluted weighted average limited partner units	1,148.3		1,100.7			1,147.3			1,071.3
Diluted income from continuing operations per Limited Partner unit	$	0.22	$	0.19		$	0.62		$	0.71
Diluted loss from discontinued operations per Limited Partner unit	$	0.00	$	0.00		$	(0.01	)	$	0.00

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Equity (Tables)

9 Months Ended

Sep. 30, 2017

Change In ETE Common Units

The changes in ETE common units and Convertible Units during the nine months ended September 30,2017 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 September 30, 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 ETP in future periods:

	Total Year
2017 (remainder)	$	173
2018	153
2019	128
Each year beyond 2019	33

Accumulated Other Comprehensive Income

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

	September 30, 2017			December 31, 2016
Available-for-sale securities	$	7		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial gain related to pensions and other postretirement benefits	9			7
Investments in unconsolidated affiliates, net	3			4
Subtotal	14			8
Amounts attributable to noncontrolling interest	(14		)	(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
June 30, 2017 (1)	August 7, 2017	August 21, 2017	$	0.2850
September 30, 2017 (1)	November 7, 2017	November 20, 2017	0.2950

⁽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.

ETP [Member]

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

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

Quarter Ended	Record Date	Payment Date	Rate
March 31, 2017	May 10, 2017	May 15, 2017	$	0.5350
June 30, 2017	August 7, 2017	August 14, 2017	0.5500
September 30, 2017	November 7, 2017	November 14, 2017	0.5650

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
June 30, 2017	August 7, 2017	August 15, 2017	0.8255
September 30, 2017	November 7, 2017	November 14, 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
June 30, 2017	August 7, 2017	August 21, 2017	0.1100
September 30, 2017	November 7, 2017	November 20, 2017	0.1100

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

9 Months Ended

Sep. 30, 2017

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

Schedule of Rent Expense [Table Text Block]

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2047.  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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Rental expense	$	42		$	31		$	106		$	94
Less: Sublease rental income	(6		)	(6		)	(19		)	(18		)
Rental expense, net	$	36		$	25		$	87		$	76

Environmental Exit Costs by Cost

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.

	September 30, 2017		December 31, 2016
Current	$	42	$	31
Non-current	302		318
Total environmental liabilities	$	344	$	349

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Derivative Assets And Liabilities (Tables)

9 Months Ended

Sep. 30, 2017

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:

	September 30, 2017			December 31, 2016
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,297,500		2017-2018	(682,500	)	2017
Basis Swaps IFERC/NYMEX (1)	(15,810,000	)	2017-2019	2,242,500		2017
Options – Puts	13,000,000		2018	—		—
Power (Megawatt):
Forwards	665,040		2017-2018	391,880		2017-2018
Futures	(213,840	)	2017-2018	109,564		2017-2018
Options — Puts	(280,800	)	2017-2018	(50,400	)	2017
Options — Calls	545,600		2017-2018	186,400		2017
Crude (Bbls):
Futures	(160,000	)	2017	(617,000	)	2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	67,500		2017-2020	10,750,000		2017-2018
Swing Swaps IFERC	91,897,500		2017-2019	(5,662,500	)	2017
Fixed Swaps/Futures	(20,220,000	)	2017-2019	(52,652,500	)	2017-2019
Forward Physical Contracts	(140,937,993	)	2017-2018	(22,492,489	)	2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(8,744,200	)	2017-2019	(5,786,627	)	2017
Refined Products (Bbls) — Futures	(1,947,000	)	2017-2018	(3,144,000	)	2017
Corn (Bushels) — Futures	650,000		2017-2018	1,580,000		2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2017	(36,370,000	)	2017
Fixed Swaps/Futures	(41,102,500	)	2017	(36,370,000	)	2017
Hedged Item — Inventory	41,102,500		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)	September 30, 2017		December 31, 2016
July 2017(2)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018(2)	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019(2)	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020(2)	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300

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

⁽²⁾  Represents the effective date. These forward-starting swaps have 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
	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	7	$	—	$	—		$	(4	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	222	$	338	$	(262	)	$	(416	)
Commodity derivatives	52		25		(61		)	(58		)
Interest rate derivatives	—		—		(210		)	(193		)
Embedded derivatives in the ETP Preferred Units	—		—		—			(1		)
	274		363		(533		)	(668		)
Total derivatives	$	281	$	363	$	(533	)	$	(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	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	—		$	—		$	(210	)	$	(194	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	52			25			(61		)	(58		)
Broker cleared derivative contracts	Other current assets	229			338			(262		)	(420		)
Total gross derivatives		281			363			(533		)	(672		)
Less offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(10		)	(4		)	10			4
Payments on margin deposit	Other current assets	(220		)	(338		)	220			338
Total net derivatives		$	51		$	21		$	(303	)	$	(330	)

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 September 30,					Nine Months Ended September 30,
		2017		2016			2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	2	$	(9	)	$	4	$	8
Total		$	2	$	(9	)	$	4	$	8

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 September 30,						Nine Months Ended September 30,
		2017			2016			2017			2016
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading	Cost of products sold	$	(5	)	$	(7	)	$	21		$	(24	)
Commodity derivatives —Non-trading	Cost of products sold	(25		)	(16		)	(6		)	(61		)
Interest rate derivatives	Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Embedded derivatives	Other, net	—			8			1			4
Total		$	(38	)	$	(43	)	$	(12	)	$	(260	)

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Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2017

Operating Segments [Member]

Financial Information By Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Segment Adjusted EBITDA:
Investment in ETP	$	1,744		$	1,390		$	4,757		$	4,172
Investment in Sunoco LP	199			189			574			512
Investment in Lake Charles LNG	43			45			131			133
Corporate and Other	(3		)	(37		)	(25		)	(142		)
Adjustments and Eliminations	(74		)	(83		)	(211		)	(208		)
Total	1,909			1,504			5,226			4,467
Depreciation, depletion and amortization	(632		)	(548		)	(1,840		)	(1,596		)
Interest expense, net	(505		)	(474		)	(1,471		)	(1,336		)
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Non-cash unit-based compensation expense	(29		)	(23		)	(76		)	(46		)
Unrealized gains (losses) on commodity risk management activities	(76		)	(21		)	22			(105		)
Losses on extinguishments of debt	—			—			(25		)	—
Inventory valuation adjustments	141			35			38			203
Equity in earnings of unconsolidated affiliates	92			49			228			205
Adjusted EBITDA related to unconsolidated affiliates	(205		)	(157		)	(554		)	(503		)
Adjusted EBITDA related to discontinued operations	(92		)	(93		)	(253		)	(220		)
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Other, net	46			4			111			44
Income (loss) before income tax benefit	$	641		$	(60	)	$	1,378		$	626

Assets Segments [Member]

Financial Information By Segment

	September 30, 2017			December 31, 2016
Assets:
Investment in ETP	$	77,011		$	70,191
Investment in Sunoco LP	8,307			8,701
Investment in Lake Charles LNG	1,611			1,508
Corporate and Other	620			711
Adjustments and Eliminations	(2,169		)	(2,100		)
Total assets	$	85,380		$	79,011

Sales Revenue, Segment [Member]

Financial Information By Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Revenues:
Investment in ETP:
Revenues from external customers	$	6,876		$	5,488		$	20,168		$	15,167
Intersegment revenues	97			43			276			134
	6,973			5,531			20,444			15,301
Investment in Sunoco LP:
Revenues from external customers	2,549			2,167			7,321			5,912
Intersegment revenues	6			—			9			6
	2,555			2,167			7,330			5,918
Investment in Lake Charles LNG:
Revenues from external customers	49			50			148			148
Adjustments and Eliminations	(103		)	(43		)	(285		)	(140		)
Total revenues	$	9,474		$	7,705		$	27,637		$	21,227

Investment In ETP [Member]

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

Investment in ETP

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Intrastate Transportation and Storage	$	729	$	583	$	2,196	$	1,457
Interstate Transportation and Storage	220		231		652		714
Midstream	665		582		1,863		1,799
NGL and refined products transportation and services	1,989		1,397		5,874		4,014
Crude oil transportation and services	2,714		1,856		7,749		5,146
All Other	656		882		2,110		2,171
Total revenues	6,973		5,531		20,444		15,301
Less: Intersegment revenues	97		43		276		134
Revenues from external customers	$	6,876	$	5,488	$	20,168	$	15,167

Investment In Sunoco LP [Member]

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

Investment in Sunoco LP

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Retail operations	$	88	$	80	$	247	$	241
Wholesale operations	2,467		2,087		7,083		5,677
Total revenues	2,555		2,167		7,330		5,918
Less: Intersegment revenues	6		—		9		6
Revenues from external customers	$	2,549	$	2,167	$	7,321	$	5,912

XML

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

9 Months Ended

Sep. 30, 2017

Schedule Of Balance Sheets

BALANCE SHEETS

(unaudited)

	September 30, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	2
Accounts receivable from related companies	64			55
Other current assets	2			—
Total current assets	66			57
Property, plant and equipment, net	27			36
Advances to and investments in unconsolidated affiliates	6,031			5,088
Intangible assets, net	—			1
Goodwill	9			9
Other non-current assets, net	17			10
Total assets	$	6,150		$	5,201
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	1
Accounts payable to related companies	—			22
Interest payable	79			66
Accrued and other current liabilities	3			3
Total current liabilities	82			92
Long-term debt, less current maturities	6,684			6,358
Long-term notes payable – related companies	574			443
Other non-current liabilities	2			2
Commitments and contingencies
Partners’ capital:
General Partner	(3		)	(3		)
Limited Partners:
Common Unitholders	(1,566		)	(1,871		)
Series A Convertible Preferred Units	377			180
Total partners’ deficit	(1,192		)	(1,694		)
Total liabilities and equity	$	6,150		$	5,201

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(3	)	$	(75	)	$	(25	)	$	(156	)
OTHER INCOME (EXPENSE):
Interest expense, net	(88		)	(81		)	(257		)	(244		)
Equity in earnings of unconsolidated affiliates	343			367			1,012			1,166
Losses on extinguishments of debt	—			—			(25		)	—
Other, net	—			(2		)	(2		)	(4		)
NET INCOME	252			209			703			762
General Partner’s interest in net income	1			—			2			2
Convertible Unitholders’ interest in income	11			2			25			3
Limited Partners’ interest in net income	$	240		$	207		$	676		$	757

⁽¹⁾  Prior periods include 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)

	Nine Months Ended September 30,
	2017			2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	620		$	718
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(861		)	(70		)
Capital expenditures	(1		)	(15		)
Contributions in aid of construction costs	7			—
Net cash used in investing activities	(855		)	(85		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,116			180
Principal payments on debt	(1,795		)	(155		)
Proceeds from affiliate	131			129
Distributions to partners	(752		)	(780		)
Units issued for cash	568			—
Debt issuance costs	(35		)	—
Net cash provided by (used in) financing activities	233			(626		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(2		)	7
CASH AND CASH EQUIVALENTS, beginning of period	2			1
CASH AND CASH EQUIVALENTS, end of period	$	—		$	8

XML

Operations And Organization Narrative (Details)	1 Months Ended		9 Months Ended
	Apr. 30, 2017 shares	Mar. 31, 2017	Sep. 30, 2017 shares
SXL and ETP Merger [Member]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.5
Sale of Stock, Number of Shares Issued in Transaction	832,000,000
ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.			18,400,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		3.30%
Post-Merger ETP [Member]
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.			27,500,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			2.50%
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.			81,000,000
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.			100
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.			100

XML

Acquisitions Narrative (Details) $ in Millions	1 Months Ended					3 Months Ended		9 Months Ended
	Oct. 31, 2017	Jul. 31, 2017	Apr. 30, 2017 USD ($)	Mar. 31, 2017	Feb. 28, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)
Intangible assets, net						$ 6,195		$ 6,195	$ 5,489
Property, plant and equipment						68,730		$ 68,730	$ 61,158
7-Eleven Transaction [Member]
Payments to Acquire Businesses, Gross			$ 3,300
Number of Stores			1,112
Discontinued Operations, Held-for-sale [Member]
Number of Stores			208
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross					$ 2,000
Post-Merger ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest								2.50%
ETP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				3.30%
Sunoco LP [Member]
Goodwill, Impairment Loss						$ 44	$ 320
Stores held for sale and currently under contract [Member] | Discontinued Operations, Held-for-sale [Member]
Number of Stores						14		14
Sold in another transaction [Member] | Discontinued Operations, Held-for-sale [Member]
Number of Stores						10		10
Stores held for sale [Member] | Discontinued Operations, Held-for-sale [Member]
Number of Stores						97		97
Stores held for sale and currently sold [Member] | Discontinued Operations, Held-for-sale [Member]
Number of Stores						27		27
7-Eleven Transaction [Member] | Discontinued Operations, Held-for-sale [Member]
Number of Stores						31		31
Currently being marketed [Member] | Discontinued Operations, Held-for-sale [Member]
Number of Stores						15		15
Holdco [Member] | ETP [Member] | Rover Contribution [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		49.90%
Energy Transfer Crude Oil Company, LLC [Member] | Dakota Access, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		15.00%
Sunoco Logistics [Member] | Bakken Holdings Company LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					100.00%
Sunoco Logistics [Member] | Permian Express Partners LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		88.00%
Proceeds from Noncontrolling Interests								$ 988
Intangible assets, net						$ 547		547
Property, plant and equipment						$ 435		$ 435
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%
Rover Pipeline LLC [Member] | Holdco [Member] | Rover Contribution [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		65.00%
Subsequent Event [Member] | ETP [Member] | Rover Contribution [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.10%

XML

Acquisitions Discontinued Operations - Balance Sheet Data (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents	$ 24	$ 20
Inventories	183	188
Other current assets	91	83
Property, plant and equipment, net	2,132	2,185
Goodwill	1,216	1,568
Intangible assets, net	499	503
Other non-current assets, net	2	2
Total assets classified as held for sale in the Consolidated Balance Sheet	4,147	4,549
Total liabilities classified as held for sale in the Consolidated Balance Sheet	81	0
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent	$ 0	$ 68

XML

Acquisitions Discontinued Operations - Income Statement Data (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
REVENUES	$ 2,312	$ 1,970	$ 6,580	$ 5,474
Cost of products sold	1,927	1,585	5,478	4,445
Operating expenses	236	250	727	727
Depreciation, depletion and amortization	5	47	68	149
Selling, general and administrative	57	37	122	74
Disposal Group, Including Discontinued Operations, Total Costs and Expenses	2,225	1,919	6,395	5,395
OPERATING INCOME	87	51	185	79
Interest expense, net	13	7	22	22
Other, net	38	1	367	4
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)	36	43	(204)	53
Discontinued Operation, Tax Effect of Discontinued Operation	30	31	60	29
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	6	12	(264)	24
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ 0	$ 0	$ (9)	$ 0

XML

Cash And Cash Equivalents Non-Cash Activities (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 1,237	$ 1,001
Losses from subsidiary common unit issuances, net	(57)	(3)
Non-Cash Financing [Abstract]
Long-term debt exchanged in Regency’s acquisitions	$ 988	$ 0

XML

Inventories Table - Inventory Balances (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Inventory, Net [Abstract]
Natural gas and NGLs	$ 609	$ 699
Crude oil	696	683
Refined products	413	483
Other	239	238
Total inventories	$ 1,957	$ 2,103

XML

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 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	47,210	$ 45,050
Long-term Debt	$ 45,210	$ 43,800

XML

Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 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	$ 281	363
Assets, Fair Value Disclosure	281	363
Interest Rate Derivative Liabilities, at Fair Value	(210)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value	(323)	(478)
Liabilities, Fair Value Disclosure, Recurring	(533)
Fair Value, Measurements, Recurring [Member] | Level 1
Price Risk Derivative Assets, at Fair Value	265	356
Assets, Fair Value Disclosure	265	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	(311)	(470)
Liabilities, Fair Value Disclosure, Recurring	(311)
Fair Value, Measurements, Recurring [Member] | Level 2
Price Risk Derivative Assets, at Fair Value	16	7
Assets, Fair Value Disclosure	16	7
Interest Rate Derivative Liabilities, at Fair Value	(210)	(193)
Embedded Derivative, Fair Value of Embedded Derivative Liability		0
Price Risk Derivative Liabilities, at Fair Value	(12)	(8)
Liabilities, Fair Value Disclosure, Recurring	(222)
Fair Value, Measurements, Recurring [Member] | Level 3
Price Risk Derivative Assets, at Fair Value		0
Assets, Fair Value Disclosure		0
Interest Rate Derivative Liabilities, at Fair Value		0
Embedded Derivative, Fair Value of Embedded Derivative Liability		(1)
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	16	14
Price Risk Derivative Liabilities, at Fair Value	(22)	(11)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	2	2
Price Risk Derivative Liabilities, at Fair Value	(3)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	28	96
Price Risk Derivative Liabilities, at Fair Value	(22)	(149)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	3	1
Price Risk Derivative Liabilities, at Fair Value	(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	16	14
Price Risk Derivative Liabilities, at Fair Value	(22)	(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	0
Price Risk Derivative Liabilities, at Fair Value	(1)	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	28	96
Price Risk Derivative Liabilities, at Fair Value	(22)	(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
Price Risk Derivative Liabilities, at Fair Value	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	2
Price Risk Derivative Liabilities, at Fair Value	(2)	(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	3	1
Price Risk Derivative Liabilities, at Fair Value	(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
Price Risk Derivative Liabilities, at Fair Value		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
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		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
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	4	2
Price Risk Derivative Liabilities, at Fair Value	(3)	(23)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value	4	2
Price Risk Derivative Liabilities, at Fair Value	(3)	(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
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	2	9
Price Risk Derivative Liabilities, at Fair Value	(1)	(13)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value	2	9
Price Risk Derivative Liabilities, at Fair Value	(1)	(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
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	11	4
Price Risk Derivative Liabilities, at Fair Value	(9)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [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] | Options - Puts [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 | Fixed Swaps/Futures [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 | Options - Puts [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	11	4
Price Risk Derivative Liabilities, at Fair Value	(9)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 | Fixed Swaps/Futures [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 2 | Options - Puts [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
Price Risk Derivative Liabilities, 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	213	233
Price Risk Derivative Liabilities, at Fair Value	(261)	(273)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	213	233
Price Risk Derivative Liabilities, at Fair Value	(261)	(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
Price Risk Derivative Liabilities, at Fair Value		$ 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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Income from continuing operations	$ 798	$ 29	$ 1,475	$ 777
Less: Income (loss) from continuing operations attributable to noncontrolling interest	546	(180)	763	15
Income from continuing operations, net of noncontrolling interest	252	209	712	762
Less: General Partner’s interest in income	1	0	2	2
Less: Convertible Unitholders’ interest in income	11	2	25	3
Income from continuing operations available to Limited Partners	$ 240	$ 207	$ 685	$ 757
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,079.1	1,045.5	1,077.9	1,045.0
Basic income from continuing operations per Limited Partner unit	$ 0.22	$ 0.20	$ 0.64	$ 0.72
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	$ 0.00	$ 0.00	$ (0.01)	$ 0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders	$ (10)	$ (2)	$ (25)	$ (3)
Diluted income from continuing operations available to Limited Partners	$ 250	$ 209	$ 710	$ 760
Dilutive effect of unconverted unit awards and Convertible Units	69.2	55.2	69.4	26.3
Diluted weighted average limited partner units	1,148.3	1,100.7	1,147.3	1,071.3
Diluted income from continuing operations per Limited Partner unit	$ 0.22	$ 0.19	$ 0.62	$ 0.71
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	$ 0.00	$ 0.00	$ (0.01)	$ 0.00

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Debt Obligations Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended
	Oct. 31, 2017	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Apr. 30, 2015
Debt Instrument [Line Items]
Repayments of Long-term Debt			$ 22,586	$ 13,955
Proceeds from Issuance of Senior Long-term Debt		$ 2,220
Proceeds from Issuance of Long-term Debt			23,988	18,288
Parent Company [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			1,795	155
Proceeds from Issuance of Long-term Debt			2,116	$ 180
ETE Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		1,500	1,500
Line Of Credit Facility, Additional Borrowing Capacity Subject To Lender Approval		500	500
Letters Of Credit Availablity		150	150
ETE Senior Secured Revolving Credit Facilities [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		1,190	1,190
Line of Credit Facility, Remaining Borrowing Capacity		309	309
ETLP Credit Facility due November 2019 [Member] | ETLP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		3,750	3,750
Long-term Line of Credit		2,060	2,060
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	2,500
Long-term Line of Credit		35	35
Line of Credit Facility, Maximum Borrowing Capacity		3,250	3,250
Bakken Term Note [Member] | Bakken Pipeline [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		2,500	2,500
4.0% Senior Notes due October 2027 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 750	$ 750
Debt Instrument, Interest Rate, Stated Percentage		4.00%	4.00%
5.40% Senior Notes due October 2047 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 1,500	$ 1,500
Debt Instrument, Interest Rate, Stated Percentage		5.40%	5.40%
6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument [Line Items]
Early Repayment of Senior Debt		$ 500
Debt Instrument, Interest Rate, Stated Percentage		6.50%	6.50%
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	$ 1,500			$ 1,250
Long-term Line of Credit		644	644
Letters of Credit Outstanding, Amount		9	9
Line of Credit Facility, Remaining Borrowing Capacity		847	847
ETE Senior Secured Term Loan due December 2, 2019 [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Secured Debt		2,200	$ 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 ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, 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 27.5 million common units representing limited partner interests in 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 ETP.
Bakken Project $2.50 billion Credit Facility due August 2019 [Member] | Bakken Project [Member]
Debt Instrument [Line Items]
Long-term Line of Credit		2,500	$ 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	275
Term loan due 2019 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		2,035	2,035
Long-term Line of Credit		$ 1,240	$ 1,240
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
Subsequent Event [Member]
Debt Instrument [Line Items]
Early Repayment of Senior Debt	$ 1,230
Proceeds from Issuance of Senior Long-term Debt	990
Subsequent Event [Member] | 6.5% Senior Notes due May 15, 2021 [Member]
Debt Instrument [Line Items]
Early Repayment of Senior Debt	$ 500
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Subsequent Event [Member] | 5.5% Senior Notes, due April 15, 2023 [Member]
Debt Instrument [Line Items]
Early Repayment of Senior Debt	$ 700
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Subsequent Event [Member] | 4.25% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior Notes	$ 1,000
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Letter of Credit [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate			2.75%
Letter of Credit [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate			1.75%
Base Rate Loans [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
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) shares in Millions, $ in Millions	1 Months Ended
	Jan. 31, 2017 USD ($) shares
Payments for Repurchase of Preferred Stock and Preference Stock | $	$ 53
ETP Series A Preferred Units [Member]
Partners' Capital Account, Units, Redeemed | shares	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
		Aug. 31, 2017	Mar. 31, 2017	Feb. 28, 2017	Jan. 31, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2017	Sep. 30, 2016	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			1,046.9	1,079.1
Series A Convertible Preferred Units							$ 377			$ 180	$ 377
Losses from subsidiary common unit issuances, net											(57)	$ (3)
Partners' Capital Account, Units, Sold in Public Offering		54.0
Proceeds from Issuance of Common Limited Partners Units		$ 997									568	0
Stock Repurchase Program, Remaining Authorized Repurchase Amount							936				936
Preferred Units, Preferred Partners' Capital Accounts							$ 26,640			$ 22,517	26,640
Sale of Bakken Pipeline 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							Nov. 20, 2017	Aug. 21, 2017	May 19, 2017	Feb. 21, 2017
Payments to Acquire Additional Interest in Subsidiaries											(7)	0
Series A Convertible Preferred Units							$ 377			$ 180	377
Proceeds from Issuance of Common Limited Partners Units											$ 568	$ 0
Rate	[1]						$ 0.2950	$ 0.2850	$ 0.2850	$ 0.2850
Record Date							Nov. 07, 2017	Aug. 07, 2017	May 10, 2017	Feb. 07, 2017
Post-Merger ETP [Member]
Payment Date							Nov. 14, 2017	Aug. 14, 2017	May 15, 2017
Rate							$ 0.5650	$ 0.5500	$ 0.5350
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest											2.50%
Record Date							Nov. 07, 2017	Aug. 07, 2017	May 10, 2017
ETP [Member]
Stock Issued During Period, Value, Dividend Reinvestment Plan											$ 106
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units							$ 1,000
Rate										$ 0.7033
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			3.30%
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement											$ 498
Partners' Capital Account, Units, Sold in Private Placement					23.7
Proceeds from Issuance of Private Placement					$ 568
Sunoco Logistics [Member]
Rate										$ 0.52
PennTex [Member]
Sale of Stock, Price Per Share							$ 20.00				$ 20.00
Sunoco LP [Member]
Payment Date							Nov. 14, 2017	Aug. 15, 2017	May 16, 2017	Feb. 21, 2017
Equity Distribution Agreements, Value of Units Available to be Issued							$ 295				$ 295
Rate							$ 0.8255	$ 0.8255	$ 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							Nov. 07, 2017	Aug. 07, 2017	May 09, 2017	Feb. 13, 2017
ETE [Member]
Equity Distribution Agreements, Value of Units Available to be Issued							$ 1,000				$ 1,000
Series A Convertible Preferred Units [Member]
Preferred Units, Preferred Partners' Capital Accounts							377			$ 180	377
Sale of Bakken Pipeline interest											0
Common Unitholders
Preferred Units, Preferred Partners' Capital Accounts							$ (1,566)			$ (1,871)	(1,566)
Sale of Bakken Pipeline interest											$ 42
Second Target Distribution [Member]
Distribution Payment Targets							0.0833
Convertible Preferred Stock [Member]
Issuance of common units											0.0
Limited Partners' Capital Account, Units Outstanding							329.3			329.3	329.3
Equity Distribution Agreement [Member] | ETP [Member]
Fees and Commissions											$ 5
Bakken Equity Sale [Member]
Payments to Acquire Businesses, Gross				$ 2,000
Subsequent Event [Member] | ETE [Member]
Relinquishment of Incentive Distributions						$ 173							$ 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				100.00%
Maximum [Member] | IDRs [Member]
Marginal Percentage Interest in Distributions							50.00%				50.00%
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	9 Months Ended
	Sep. 30, 2017 shares
Class of Stock [Line Items]
Outstanding at December 31, 2016	1,046.9
Issuance of common units	32.2
Outstanding at September 30, 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 September 30, 2017	329.3

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Equity Table - Quarterly Distributions of Available Cash (Details) - $ / shares		3 Months Ended
		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Post-Merger ETP [Member]
Record Date		Nov. 07, 2017	Aug. 07, 2017	May 10, 2017
Payment Date		Nov. 14, 2017	Aug. 14, 2017	May 15, 2017
Rate		$ 0.5650	$ 0.5500	$ 0.5350
Parent Company [Member]
Record Date		Nov. 07, 2017	Aug. 07, 2017	May 10, 2017	Feb. 07, 2017
Payment Date		Nov. 20, 2017	Aug. 21, 2017	May 19, 2017	Feb. 21, 2017
Rate	[1]	$ 0.2950	$ 0.2850	$ 0.2850	$ 0.2850
ETP [Member]
Rate					0.7033
Sunoco Logistics [Member]
Rate					$ 0.52
Sunoco LP [Member]
Record Date		Nov. 07, 2017	Aug. 07, 2017	May 09, 2017	Feb. 13, 2017
Payment Date		Nov. 14, 2017	Aug. 15, 2017	May 16, 2017	Feb. 21, 2017
Rate		$ 0.8255	$ 0.8255	$ 0.8255	$ 0.8255
Convertible Units [Member] | Parent Company [Member]
Record Date		Nov. 07, 2017	Aug. 07, 2017	May 10, 2017	Feb. 07, 2017
Payment Date		Nov. 20, 2017	Aug. 21, 2017	May 19, 2017	Feb. 21, 2017
Rate		$ 0.1100	$ 0.1100	$ 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 - IDR Schedule (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ETE [Member] | Subsequent Event [Member]
Relinquishment of Incentive Distributions	$ 173	$ 33	$ 128	$ 153

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Equity Table - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 7	$ 2
Foreign currency translation adjustment	(5)	(5)
Actuarial gain related to pensions and other postretirement benefits	9	7
AOCI attributable to equity method investments	3	4
Subtotal	14	8
Amounts attributable to noncontrolling interest	(14)	(8)
Accumulated other comprehensive income, net	$ 0	$ 0

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 68
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Restructuring Charges, Amount	$ 154

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended			3 Months Ended		9 Months Ended		12 Months Ended
	May 31, 2017 USD ($)	Apr. 30, 2015 USD ($)	Jan. 31, 2012 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)
Loss Contingency Accrual, at Carrying Value				$ 68,000,000		$ 68,000,000			$ 77,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed				0		0
Payments for Environmental Liabilities				7,000,000	$ 12,000,000	22,000,000	$ 31,000,000
Accrual for Environmental Loss Contingencies				$ 344,000,000		$ 344,000,000			$ 349,000,000
AmeriGas [Member]
Debt Instrument, Interest Rate, Stated Percentage				7.00%		7.00%
Contingent Residual Support Agreement, Amount			$ 1,550,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number				6		6
Proposed Environmental Penalty				$ 200,000		$ 200,000
Williams [Member]
Loss on Contract Termination for Default						410,000,000
Loss Contingency, Damages Sought, Value						$ 10,000,000,000
BP Products North America [Member]
Loss Contingency, Damages Awarded, Value	$ 13,000,000	$ 62,000,000						$ 41,000,000
Sunoco [Member]
Site Contingency, Number of Sites Needing Remediation				44		44
Sunoco Logistics [Member]
Proposed Environmental Penalty				$ 100,000		$ 100,000
Rover Pipeline LLC [Member]
Site Contingency, Number of Sites Needing Remediation				27		27
Proposed Environmental Penalty				$ 2,300,000		$ 2,300,000
Federal [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty				7,000,000		7,000,000
State and Local Jurisdiction [Member] | Sunoco Pipeline L.P. [Member]
Proposed Environmental Penalty				$ 1,000,000		$ 1,000,000
Multidistrict Legislation [Member] | Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number				4		4
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount				$ 319,000,000		$ 319,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount				536,000,000		536,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount				1,000,000		1,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount				$ 595,000,000		595,000,000
ETE Defendants [Member] | Williams [Member]
Loss Contingency, Damages Sought, Value						$ 1,480,000,000

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Rent expense table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Rental expense	$ 42	$ 31	$ 106	$ 94
Less: Sublease rental income	(6)	(6)	(19)	(18)
Rental expense, net	$ 36	$ 25	$ 87	$ 76

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Environmental Exit Cost [Line Items]
Current	$ 42	$ 31
Non-current	302	318
Total environmental liabilities	$ 344	$ 349

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Derivative Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)		9 Months Ended	12 Months Ended
		Sep. 30, 2017 bushels barrels Megawatt bbl MMbtu	Dec. 31, 2016 bushels barrels Megawatt bbl MMbtu
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Maximum Term Of Commodity Derivatives		2018
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forward Physical Contracts [Member]
Maximum Term Of Commodity Derivatives		2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Long [Member]
Notional Volume		67,500	10,750,000
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Short [Member]
Notional Volume			5,662,500
Maximum Term Of Commodity Derivatives			2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Long [Member]
Notional Volume		91,897,500
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member]
Notional Volume		20,220,000	52,652,500
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Short [Member]
Notional Volume		140,937,993	22,492,489
Maximum Term Of Commodity Derivatives			2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member]
Notional Volume	[1]	15,810,000
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Long [Member]
Notional Volume	[1]		2,242,500
Maximum Term Of Commodity Derivatives			2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member]
Notional Volume			682,500
Maximum Term Of Commodity Derivatives			2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Long [Member]
Notional Volume		1,297,500
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member]
Maximum Term Of Commodity Derivatives		2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Long [Member]
Notional Volume		13,000,000	0
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Maximum Term Of Commodity Derivatives		2020	2018
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Swing Swaps IFERC [Member]
Maximum Term Of Commodity Derivatives		2019
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] | Maximum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Maximum Term Of Commodity Derivatives		2019
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Maximum Term Of Commodity Derivatives		2018
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] | Swing Swaps IFERC [Member]
Maximum Term Of Commodity Derivatives		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] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member]
Maximum Term Of Commodity Derivatives		2017
Natural Gas [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Fixed Swaps/Futures [Member]
Maximum Term Of Commodity Derivatives		2017
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Short [Member]
Notional Volume		41,102,500	36,370,000
Maximum Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Short [Member]
Notional Volume		41,102,500	36,370,000
Maximum Term Of Commodity Derivatives		2017	2017
Natural Gas [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Long [Member]
Notional Volume		41,102,500	36,370,000
Maximum Term Of Commodity Derivatives		2017	2017
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Short [Member]
Notional Volume | Megawatt		280,800	50,400
Maximum Term Of Commodity Derivatives			2017
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Long [Member]
Notional Volume | Megawatt		545,600	186,400
Maximum Term Of Commodity Derivatives			2017
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member] | Long [Member]
Notional Volume | Megawatt		665,040	391,880
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Short [Member]
Notional Volume | Megawatt		213,840
Power [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Long [Member]
Notional Volume | Megawatt			109,564
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Options - Puts [Member]
Maximum Term Of Commodity Derivatives		2018
Power [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Call Option [Member]
Maximum Term Of Commodity Derivatives		2018
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] | Options - Puts [Member]
Maximum Term Of Commodity Derivatives		2017
Power [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Call Option [Member]
Maximum Term Of Commodity Derivatives		2017
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
WTI Crude Oil [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Short [Member]
Notional Volume | bbl		160,000	617,000
Maximum Term Of Commodity Derivatives		2017	2017
Natural Gas Liquids and Crude [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Short [Member]
Notional Volume | bbl		8,744,200	5,786,627
Maximum Term Of Commodity Derivatives			2017
Natural Gas Liquids and Crude [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forwards Swaps [Member]
Maximum Term Of Commodity Derivatives		2018
Natural Gas Liquids and Crude [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forwards Swaps [Member]
Maximum Term Of Commodity Derivatives		2017
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Short [Member]
Notional Volume | barrels		1,947,000	3,144,000
Maximum Term Of Commodity Derivatives			2017
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member]
Maximum Term Of Commodity Derivatives		2018
Refined Products [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member]
Maximum Term Of Commodity Derivatives		2017
Corn [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Long [Member]
Notional Volume | bushels		650,000	1,580,000
Maximum Term Of Commodity Derivatives			2017
Corn [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member]
Maximum Term Of Commodity Derivatives		2018
Corn [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member]
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		9 Months Ended
		Sep. 30, 2017	Dec. 31, 2016
March 2019 [Member]
Notional Amount		$ 300	$ 300
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
December 2018 [Member]
Notional Amount		$ 1,200	1,200
Type	[1]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%
July 2020 [Member]
Notional Amount	[2]	$ 400	0
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate
July 2019 [Member]
Notional Amount	[2]	$ 300	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate
July 2018 [Member]
Notional Amount	[2]	$ 300	200
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate
July 2017 [Member]
Notional Amount	[2]	$ 0	$ 500
Type	[1],[2]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate

[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.

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Derivative Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Total derivatives assets	$ 281	$ 363
Total derivatives liabilities	(533)	(672)
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	7	0
Total derivatives liabilities	0	(4)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	274	363
Total derivatives liabilities	(533)	(668)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	222	338
Total derivatives liabilities	(262)	(416)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	52	25
Total derivatives liabilities	(61)	(58)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	(210)	(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	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 281	$ 363
Derivative Liability, Fair Value, Gross Liability	(533)	(672)
Counterparty netting	(10)	(4)
Counterparty netting	10	4
Payments on margin deposit	(220)	(338)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	220	338
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	51	21
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(303)	(330)
Without offsetting agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	210	194
OTC Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	52	25
Derivative Liability, Fair Value, Gross Liability	(61)	(58)
Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	229	338
Derivative Liability, Fair Value, Gross Liability	$ (262)	$ (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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ 2	$ (9)	$ 4	$ 8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(38)	(43)	(12)	(260)
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(5)	(7)	21	(24)
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	2	(9)	4	8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(25)	(16)	(6)	(61)
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(8)	(28)	(28)	(179)
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ 0	$ 8	$ 1	$ 4

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Related Party Transactions Related Party Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Related Party Transactions [Abstract]
Revenue from Related Parties	$ 105	$ 49	$ 201	$ 175

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Reportable Segments Table - Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,909	$ 1,504	$ 5,226	$ 4,467
Depreciation, depletion and amortization	632	548	1,840	1,596
Interest expense, net	505	474	1,471	1,336
Losses on interest rate derivatives	(8)	(28)	(28)	(179)
Non-cash unit-based compensation expense	(29)	(23)	(76)	(46)
Unrealized gains (losses) on commodity risk management activities	(76)	(21)	22	(105)
Losses on extinguishments of debt	0	0	(25)	0
Inventory valuation adjustments	141	35	38	203
Equity in earnings of unconsolidated affiliates	92	49	228	205
Adjusted EBITDA related to unconsolidated affiliates	(205)	(157)	(554)	(503)
Impairment of investment in an unconsolidated affiliate	0	308	0	308
Other, net	(46)	(4)	(111)	(44)
INCOME (LOSS) BEFORE INCOME TAX BENEFIT	641	(60)	1,378	626
Adjusted EBITDA attributable to discontinued operations	(92)	(93)	(253)	(220)
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,744	1,390	4,757	4,172
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	199	189	574	512
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	43	45	131	133
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	(3)	(37)	(25)	(142)
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ (74)	$ (83)	$ (211)	$ (208)

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Reportable Segments Table - Segment Assets (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Assets	$ 85,380	$ 79,011
Investment In ETP [Member]
Assets	77,011	70,191
Investment In Sunoco LP [Member]
Assets	8,307	8,701
Investment in Lake Charles LNG [Member]
Assets	1,611	1,508
Corporate and Other [Member]
Assets	620	711
Adjustments And Eliminations [Member]
Assets	$ (2,169)	$ (2,100)

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Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues	$ 9,474	$ 7,705	$ 27,637	$ 21,227
Investment In ETP [Member]
Revenues	6,973	5,531	20,444	15,301
Investment In Sunoco LP [Member]
Revenues	2,555	2,167	7,330	5,918
Adjustments And Eliminations [Member]
Revenues	(103)	(43)	(285)	(140)
Intersegment [Member] | Investment In ETP [Member]
Revenues	97	43	276	134
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenues	6	0	9	6
External Customers [Member] | Investment In ETP [Member]
Revenues	6,876	5,488	20,168	15,167
External Customers [Member] | Investment In Sunoco LP [Member]
Revenues	2,549	2,167	7,321	5,912
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues	$ 49	$ 50	$ 148	$ 148

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Reportable Segments Table - Revenues from External Customers by Segment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Revenues	$ 9,474	$ 7,705	$ 27,637	$ 21,227
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	2,555	2,167	7,330	5,918
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	6,973	5,531	20,444	15,301
Intersegment [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	6	0	9	6
Intersegment [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	97	43	276	134
External Customers [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	2,549	2,167	7,321	5,912
External Customers [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	6,876	5,488	20,168	15,167
Intrastate Transportation And Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	729	583	2,196	1,457
Interstate Transportation and Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	220	231	652	714
Midstream [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	665	582	1,863	1,799
NGL and refined products transportation and services [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	1,989	1,397	5,874	4,014
Crude oil transportation and services [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	2,714	1,856	7,749	5,146
Other Operations [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	656	882	2,110	2,171
Retail Operations [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	88	80	247	241
Wholesale Operations [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	$ 2,467	$ 2,087	$ 7,083	$ 5,677

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Supplemental Financial Statement Information Table - Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Liabilities associated with assets held for sale	$ 81	$ 0
Cash and cash equivalents	469	463	$ 458	$ 581
Accounts receivable, net	3,551	3,557
Accounts receivable from related companies	90	47
Other current assets	433	503
Total current assets	10,689	6,985
Property, plant and equipment, net	59,267	53,253
Advances to and investments in unconsolidated affiliates	3,177	3,040
Intangible assets, net	6,195	5,489
Goodwill	5,161	5,170
Other non-current assets, net	891	816
Total assets	85,380	79,011
Accounts payable	3,994	3,502
Accounts payable to related companies	46	42
Accrued and other current liabilities	2,881	2,367
Total current liabilities	7,847	7,277
Long-term debt, less current maturities	44,495	42,608
Long-term notes payable – related companies	0	250
Other non-current liabilities	1,218	1,055
Commitments and contingencies
General Partner	(3)	(3)
Common Unitholders	(1,566)	(1,871)
Series A Convertible Preferred Units	377	180
Total partners’ capital	(1,192)	(1,694)
Total liabilities and equity	85,380	79,011
Parent Company [Member]
Cash and cash equivalents	0	2	$ 8	$ 1
Accounts receivable from related companies	64	55
Other current assets	2	0
Total current assets	66	57
Property, plant and equipment, net	27	36
Advances to and investments in unconsolidated affiliates	6,031	5,088
Intangible assets, net	0	1
Goodwill	9	9
Other non-current assets, net	17	10
Total assets	6,150	5,201
Accounts payable	0	1
Accounts payable to related companies	0	22
Interest payable	79	66
Accrued and other current liabilities	3	3
Total current liabilities	82	92
Long-term debt, less current maturities	6,684	6,358
Long-term notes payable – related companies	574	443
Other non-current liabilities	2	2
Commitments and contingencies
General Partner	(3)	(3)
Common Unitholders	(1,566)	(1,871)
Series A Convertible Preferred Units	377	180
Total partners’ capital	(1,192)	(1,694)
Total liabilities and equity	$ 6,150	$ 5,201

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Supplemental Financial Statement Information Schedule of Statements of Operations (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)		$ (142)	$ (209)	$ (484)	$ (515)
Interest expense, net		(505)	(474)	(1,471)	(1,336)
Equity in earnings of unconsolidated affiliates		92	49	228	205
Losses on extinguishments of debt		0	0	(25)	0
Other, net		76	55	168	98
NET INCOME		252	209	703	762
General Partner’s interest in net income		1	0	2	2
Convertible Unitholders’ interest in income		11	2	25	3
Limited Partners’ interest in net income		240	207	676	757
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	[1]	3	(75)	(25)	(156)
Interest expense, net		88	(81)	(257)	(244)
Equity in earnings of unconsolidated affiliates		343	367	1,012	1,166
Losses on extinguishments of debt		0	0	(25)	0
Other, net		0	(2)	(2)	(4)
NET INCOME		252	209	703	762
General Partner’s interest in net income		1	0	(2)	(2)
Convertible Unitholders’ interest in income		11	2	25	3
Limited Partners’ interest in net income		$ 240	$ 207	$ 676	$ 757

[1] Prior periods include 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	9 Months Ended
	Aug. 31, 2017	Sep. 30, 2017	Sep. 30, 2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$ 3,304	$ 2,221
Cash paid for Bakken Pipeline Transaction		(293)	(330)
Contributions to unconsolidated affiliate		230	47
Capital expenditures		(6,102)	(5,877)
Net cash used in investing activities		(4,760)	(6,084)
Proceeds from borrowings		23,988	18,288
Repayments of long-term debt		(22,586)	(13,955)
Proceeds from affiliate		919	187
Distributions to partners		(752)	(780)
Net cash provided by (used in) financing activities		1,303	3,919
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		6	(123)
Cash and cash equivalents, beginning of period		463	581
Cash and cash equivalents, end of period		469	458
Proceeds from Issuance of Common Limited Partners Units	$ 997	568	0
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		620	718
Contributions to unconsolidated affiliate		861	70
Capital expenditures		(1)	(15)
Net cash used in investing activities		(855)	(85)
Proceeds from borrowings		2,116	180
Repayments of long-term debt		(1,795)	(155)
Proceeds from affiliate		131	129
Distributions to partners		(752)	(780)
Debt issuance costs		(35)	0
Net cash provided by (used in) financing activities		233	(626)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2)	7
Cash and cash equivalents, beginning of period		2	1
Cash and cash equivalents, end of period		0	8
Proceeds from Issuance of Common Limited Partners Units		$ 568	$ 0