10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2016

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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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	¨

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 July 29, 2016, the registrant had 1,044,791,157 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	36
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	49
ITEM 4. CONTROLS AND PROCEDURES	51
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	52
ITEM 1A. RISK FACTORS	52
ITEM 6. EXHIBITS	53
SIGNATURE	54

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, 2015 filed with the Securities and Exchange Commission on February 29, 2016 and “Part II — Item 1A. Risk Factors,” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 and in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

Definitions

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

/d	per day
AmeriGas	AmeriGas Partners, L.P.
AOCI	accumulated other comprehensive income (loss)
Bbls	barrels
Bcf	billion cubic feet
Btu	British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
Citrus	Citrus, LLC
Convertible Units	Series A Convertible Preferred Units in ETE
EPA	Environmental Protection Agency
ET Rover	ET Rover Pipeline LLC
ETC	Energy Transfer Corp LP
ETC OLP	La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
ETP	Energy Transfer Partners, L.P.
ETP GP	Energy Transfer Partners GP, L.P., the general partner of ETP
ETP Preferred Units	ETP’s Series A Convertible Preferred Units
Exchange Act	Securities Exchange Act of 1934
FEP	Fayetteville Express Pipeline LLC
FERC	Federal Energy Regulatory Commission
FGT	Florida Gas Transmission Company, LLC
GAAP	accounting principles generally accepted in the United States of America
HPC	RIGS Haynesville Partnership Co.
IDRs	incentive distribution rights

ii

Lake Charles LNG	Lake Charles LNG Company, LLC
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas
Lone Star	Lone Star NGL LLC
MEP	Midcontinent Express Pipeline LLC
MMBtu	million British thermal units
MTBE	methyl tertiary butyl ether
NGL	natural gas liquid, such as propane, butane and natural gasoline
NYMEX	New York Mercantile Exchange
OSHA	Federal Occupational Safety and Health Act
OTC	over-the-counter
Panhandle	Panhandle Eastern Pipe Line Company, LP
PCBs	polychlorinated biphenyl
PHMSA	Pipeline Hazardous Materials Safety Administration
Plan	the plan of the Partnership pursuant to which eligible offerees elected to forgo certain distributions on some or all of their ETE common units and reinvest those distributions in convertible units
Regency	Regency Energy Partners LP
Retail Holdings	ETP Retail Holdings LLC, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.
SEC	Securities and Exchange Commission
Southern Union	Southern Union Company
Sunoco GP	Sunoco GP LLC, the general partner of Sunoco LP
Sunoco Logistics	Sunoco Logistics Partners L.P.
Sunoco LP	Sunoco LP (previously named Susser Petroleum Partners, LP)
Susser	Susser Holdings Corporation
Transwestern	Transwestern Pipeline Company, LLC
Trunkline	Trunkline Gas Company, LLC
WMB	The Williams Companies, Inc.
WTI	West Texas Intermediate Crude

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)

	June 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	475		$	606
Accounts receivable, net	2,944			2,400
Accounts receivable from related companies	60			119
Inventories	1,929			1,636
Derivative assets	38			46
Other current assets	644			603
Total current assets	6,090			5,410
Property, plant and equipment	58,663			54,979
Accumulated depreciation and depletion	(7,277		)	(6,296		)
	51,386			48,683
Advances to and investments in unconsolidated affiliates	3,453			3,462
Non-current derivative assets	18			—
Other non-current assets, net	742			730
Intangible assets, net	5,356			5,431
Goodwill	7,515			7,473
Total assets	$	74,560		$	71,189

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)

	June 30, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,931		$	2,274
Accounts payable to related companies	20			28
Derivative liabilities	29			69
Accrued and other current liabilities	2,195			2,408
Current maturities of long-term debt	1,013			131
Total current liabilities	6,188			4,910
Long-term debt, less current maturities	38,501			36,837
Long-term notes payable – related companies	107			—
Non-current derivative liabilities	367			137
Deferred income taxes	5,215			4,590
Other non-current liabilities	1,137			1,069
Commitments and contingencies
Preferred units of subsidiary	33			33
Redeemable noncontrolling interests	15			15
Equity:
General Partner	(2		)	(2		)
Limited Partners:
Common Unitholders	(1,738		)	(952		)
Class D Units	—			22
Series A Convertible Preferred Units	59			—
Total partners’ capital (deficit)	(1,681		)	(932		)
Noncontrolling interest	24,678			24,530
Total equity	22,997			23,598
Total liabilities and equity	$	74,560		$	71,189

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
REVENUES
Natural gas sales	$	695		$	898		$	1,533		$	1,933
NGL sales	1,150			988			2,090			1,969
Crude sales	1,714			2,680			2,923			4,888
Gathering, transportation and other fees	1,087			1,035			2,090			2,081
Refined product sales	3,877			4,434			6,416			8,090
Other	821			1,559			1,974			3,013
Total revenues	9,344			11,594			17,026			21,974
COSTS AND EXPENSES
Cost of products sold	7,054			9,338			12,676			17,825
Operating expenses	688			663			1,329			1,291
Depreciation, depletion and amortization	588			514			1,150			1,007
Selling, general and administrative	187			183			343			338
Total costs and expenses	8,517			10,698			15,498			20,461
OPERATING INCOME	827			896			1,528			1,513
OTHER INCOME (EXPENSE)
Interest expense, net	(450		)	(408		)	(877		)	(779		)
Equity in earnings of unconsolidated affiliates	95			117			156			174
Losses on extinguishments of debt	—			(33		)	—			(33		)
Gains (losses) on interest rate derivatives	(81		)	127			(151		)	50
Other, net	24			17			40			24
INCOME BEFORE INCOME TAX BENEFIT	415			716			696			949
Income tax benefit	(9		)	(56		)	(64		)	(44		)
NET INCOME	424			772			760			993
Less: Net income attributable to noncontrolling interest	183			474			207			411
NET INCOME ATTRIBUTABLE TO PARTNERS	241			298			553			582
General Partner’s interest in net income	1			—			2			1
Convertible Unitholders’ interest in income	1			—			1			—
Class D Unitholder’s interest in net income	—			—			—			1
Limited Partners’ interest in net income	$	239		$	298		$	550		$	580
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.23		$	0.28		$	0.53		$	0.54
Diluted	$	0.23		$	0.28		$	0.52		$	0.54

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net income	$	424		$	772		$	760		$	993
Other comprehensive income (loss), net of tax:
Change in value of derivative instruments accounted for as cash flow hedges	—			—			—			1
Change in value of available-for-sale securities	3			(1		)	5			—
Actuarial gain (loss) relating to pension and other postretirement benefit plans	6			—			(3		)	45
Foreign currency translation adjustments	—			—			(1		)	(2		)
Change in other comprehensive income from unconsolidated affiliates	(5		)	—			(11		)	(2		)
	4			(1		)	(10		)	42
Comprehensive income	428			771			750			1,035
Less: Comprehensive income attributable to noncontrolling interest	187			470			197			450
Comprehensive income attributable to partners	$	241		$	301		$	553		$	585

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 SIX MONTHS ENDED JUNE 30, 2016

(Dollars in millions)

(unaudited)

	General Partner			Common Unitholders			Class D Units			Series A Convertible Preferred Units		Accumulated Other Comprehensive Income (Loss)		Non-controlling Interest			Total
Balance, December 31, 2015	$	(2	)	$	(952	)	$	22		$	—	$	—	$	24,530		$	23,598
Distributions to partners	(2		)	(538		)	—			—		—		—			(540		)
Distributions to noncontrolling interest	—			—			—			—		—		(1,343		)	(1,343		)
Distributions reinvested	—			(58		)	—			58		—		—			—
Subsidiary units issued	—			(12		)	—			—		—		1,087			1,075
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			(22		)	—		—		43			21
Capital contributions received from noncontrolling interest	—			—			—			—		—		161			161
Units repurchased under buyback program	—			—			—			—		—		—			—
Sunoco, Inc. retail business to Sunoco LP transaction	—			(741		)	—			—		—		—			(741		)
Other comprehensive loss, net of tax	—			—			—			—		—		(10		)	(10		)
Other, net	—			13			—			—		—		3			16
Net income	2			550			—			1		—		207			760
Balance, June 30, 2016	$	(2	)	$	(1,738	)	$	—		$	59	$	—	$	24,678		$	22,997

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)

	Six Months Ended June 30,
	2016			2015
OPERATING ACTIVITIES
Net income	$	760		$	993
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,150			1,007
Deferred income taxes	(84		)	77
Amortization included in interest expense	(1		)	(16		)
Unit-based compensation expense	23			48
(Gains) losses on disposal of assets	6			(3		)
Losses on extinguishments of debt	—			33
Inventory valuation adjustments	(168		)	(150		)
Equity in earnings of unconsolidated affiliates	(156		)	(174		)
Distributions from unconsolidated affiliates	133			162
Other non-cash	(114		)	22
Net change in operating assets and liabilities, net of effects of acquisition	(31		)	(886		)
Net cash provided by operating activities	1,518			1,113
INVESTING ACTIVITIES
Cash paid for acquisitions, net of cash received	(116		)	(475		)
Cash proceeds from sale of noncontrolling interest in Rover Pipeline LLC to AE-Midco Rover, LLC	—			64
Cash paid for acquisition of a noncontrolling interest	—			(129		)
Capital expenditures, excluding allowance for equity funds used during construction	(3,723		)	(4,181		)
Contributions in aid of construction costs	25			12
Contributions to unconsolidated affiliates	(30		)	(43		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	56			64
Proceeds from the sale of assets	16			15
Change in restricted cash	(2		)	8
Other	(1		)	(8		)
Net cash used in investing activities	(3,775		)	(4,673		)
FINANCING ACTIVITIES
Proceeds from borrowings	12,048			15,466
Repayments of long-term debt	(9,551		)	(11,301		)
Subsidiary units issued for cash	1,075			1,773
Distributions to partners	(540		)	(509		)
Debt issuance costs	(29		)	(61		)
Distributions to noncontrolling interest	(1,343		)	(1,133		)
Capital contributions received from noncontrolling interest	161			398
Units repurchased under buyback program	—			(294		)
Other, net	305			(3		)
Net cash provided by financing activities	2,126			4,336
Increase (decrease) in cash and cash equivalents	(131		)	776
Cash and cash equivalents, beginning of period	606			847
Cash and cash equivalents, end of period	$	475		$	1,623

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.

The consolidated financial statements of ETE presented herein include the results of operations of:

• the Parent Company;

• our controlled subsidiaries, ETP and Sunoco LP;

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

• our wholly-owned subsidiary, Lake Charles LNG.

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

Business Operations

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

Our financial statements reflect the following reportable business segments:

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

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

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

• Corporate and Other, including the following:

• activities of the Parent Company; and

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

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income or total equity.

7

Use of Estimates

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

Subsidiary Common Unit Transactions

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

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. The Partnership adopted this standard on January 1, 2016, and the adoption did not impact the Partnership’s financial position or results of operations.

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, if any, that adopting this new standard will have on the consolidated financial statements and related disclosures.

In March 2016, the FASB issued 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. In addition, the amendments in this update eliminate the guidance in Topic 718 that was indefinitely deferred shortly after the issuance of FASB Statement No. 123 (revised 2004), Share-Based Payment. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.

2. ACQUISITIONS AND CONTRIBUTION TRANSACTIONS

WMB Merger

On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above.

WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.

8

Sunoco Retail to Sunoco LP

In March 2016, ETP contributed to Sunoco LP its remaining68.42%interest in Sunoco, LLC and100%interest in the legacy Sunoco, Inc. retail business for$2.23 billion. Sunoco LP paid$2.20 billionin cash, including a working capital adjustment, and issued5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP. The transaction was effective January 1, 2016.

Other Sunoco LP Acquisitions

In June 2016, Sunoco LP entered into a definitive agreement to purchase the fuels business from Emerge Energy Services LP for $179 million, subject to working capital and other adjustments. The transaction is scheduled to close in the third quarter of 2016, subject to regulatory clearances and the satisfaction of other customary closing conditions. Additionally, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $45 million.

3. CASH AND CASH EQUIVALENTS

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

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

Non-cash investing activities were as follows:

	Six Months Ended June 30,
	2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	881		$	693
Gains (losses) from subsidiary common unit issuances, net	(12		)	50

4. INVENTORIES

Inventories consisted of the following:

	June 30, 2016		December 31, 2015
Natural gas and NGLs	$	552	$	415
Crude oil	564		424
Refined products	452		420
Other	361		377
Total inventories	$	1,929	$	1,636

We utilize commodity derivatives to manage price volatility associated with our 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 June 30, 2016 was $39.84 billion and $39.51 billion, respectively. As of December 31, 2015, the aggregate fair value and carrying amount of our consolidated debt obligations was $33.22 billion and $36.97 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

9

We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in the preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the six months endedJune 30, 2016, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2016 and December 31, 2015 based on inputs used to derive their fair values:

	Fair Value Measurements at June 30, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	29		$	—		$	29		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	18			18			—			—
Swing Swaps IFERC	6			—			6			—
Fixed Swaps/Futures	41			41			—			—
Forward Physical Swaps	4			—			4			—
Power:
Forwards	30			—			30			—
Futures	—			—			—			—
Options — Calls	3			3			—			—
Natural Gas Liquids – Forwards/Swaps	76			76			—			—
Refined Products — Futures	10			10			—			—
Crude – Futures	5			5			—			—
Total commodity derivatives	193			153			40			—
Total assets	$	222		$	153		$	69		$	—
Liabilities:
Interest rate derivatives	$	(358	)	$	—		$	(358	)	$	—
Embedded derivatives in the ETP Preferred Units	(9		)	—			—			(9		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(17		)	(17		)	—			—
Swing Swaps IFERC	(6		)	(1		)	(5		)	—
Fixed Swaps/Futures	(64		)	(64		)	—			—
Forward Physical Swaps	(2		)	—			(2		)	—
Power:
Forwards	(28		)	—			(28		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids – Forwards/Swaps	(88		)	(88		)	—			—
Refined Products — Futures	(21		)	(21		)	—			—
Crude — Futures	(7		)	(7		)	—			—
Total commodity derivatives	(234		)	(199		)	(35		)	—
Total liabilities	$	(601	)	$	(199	)	$	(393	)	$	(9	)

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	Fair Value Measurements at December 31, 2015
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—			—
Swing Swaps IFERC	10			2			8			—
Fixed Swaps/Futures	274			274			—			—
Forward Physical Contracts	4			—			4			—
Power:
Forwards	22			—			22			—
Futures	3			3			—			—
Options — Calls	1			1			—			—
Options — Puts	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	99			99			—			—
Refined Products — Futures	15			15			—			—
Crude - Futures	9			9			—			—
Total commodity derivatives	454			420			34			—
Total assets	$	454		$	420		$	34		$	—
Liabilities:
Interest rate derivatives	$	(171	)	$	—		$	(171	)	$	—
Embedded derivatives in the ETP Preferred Units	(5		)	—			—			(5		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(16		)	(16		)	—			—
Swing Swaps IFERC	(12		)	(2		)	(10		)	—
Fixed Swaps/Futures	(203		)	(203		)	—			—
Power:
Forwards	(22		)	—			(22		)	—
Futures	(2		)	(2		)	—			—
Options — Calls	(1		)	(1		)	—			—
Natural Gas Liquids — Forwards/Swaps	(89		)	(89		)	—			—
Refined Products — Futures	(6		)	(6		)	—			—
Crude - Futures	(5		)	(5		)	—			—
Total commodity derivatives	(356		)	(324		)	(32		)	—
Total liabilities	$	(532	)	$	(324	)	$	(203	)	$	(5	)

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the six months endedJune 30, 2016.

Balance, December 31, 2015	$	(5	)
Net unrealized gains included in other income (expense)	(4		)
Balance, June 30, 2016	$	(9	)

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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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net Income	$	424	$	772	$	760	$	993
Less: Income attributable to noncontrolling interest	183		474		207		411
Net Income, net of noncontrolling interest	241		298		553		582
Less: General Partner’s interest in income	1		—		2		1
Less: Convertible Unitholders’ interest in income	1		—		1		—
Less: Class D Unitholder’s interest in income	—		—		—		1
Income available to Limited Partners	$	239	$	298	$	550	$	580
Basic Income per Limited Partner Unit:
Weighted average limited partner units	1,048.9		1,076.0		1,046.9		1,077.2
Basic income per Limited Partner unit	$	0.23	$	0.28	$	0.53	$	0.54
Diluted Income per Limited Partner Unit:
Income available to Limited Partners	$	239	$	298	$	550	$	580
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and distributions to Convertible Unitholders	1		1		1		1
Diluted income available to Limited Partners	$	240	$	299	$	551	$	581
Weighted average limited partner units	1,048.9		1,076.0		1,046.9		1,077.2
Dilutive effect of unconverted unit awards and Convertible Units	14.9		1.6		5.6		1.8
Diluted weighted average limited partner units	1,063.8		1,077.6		1,052.5		1,079.0
Diluted income per Limited Partner unit	$	0.23	$	0.28	$	0.52	$	0.54

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.

Revolving Credit Facility

The Parent Company’s revolving credit facility has a capacity of $1.5 billion. As of June 30, 2016, there were $885 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $615 million.

Subsidiary Indebtedness

ETP Senior Notes

Subsequent to the Regency Merger in 2015, ETP assumed $3.80 billion total aggregate principal amount of Regency’s senior notes, which remained outstanding as of June 30, 2016. These notes were previously guaranteed by certain consolidated subsidiaries that had previously been consolidated by Regency. The subsidiary guarantees on all of these outstanding notes have been released.

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Sunoco Logistics Senior Notes

Sunoco Logistics had$175 millionof6.125%senior notes which matured and were repaid in May 2016, using borrowings under the$2.50 billionSunoco Logistics Credit Facility.

In July 2016, Sunoco Logistics issued$550 millionaggregate principal amount of3.90%senior notes due in July 2026. The net proceeds from this offering were used to repay outstanding credit facility borrowings and for general partnership purposes.

Sunoco LP Term Loan and Senior Notes

In March 2016, Sunoco LP entered into a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. As of June 30, 2016, Sunoco LP had $1.2 billion outstanding under the term loan. Amounts borrowed under the term loan bear interest at either LIBOR or base rate plus an applicable margin based on Sunoco LP’s election for each interest period. The proceeds were used to fund a portion of the ETP dropdown and to pay fees and expenses incurred in connection with the ETP dropdown and the term loan.

In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 2019. The indebtedness under the ETP Credit Facility is unsecured, is not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. As of June 30, 2016, the ETP Credit Facility had $1.13 billion of outstanding borrowings.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of June 30, 2016, the Sunoco Logistics Credit Facility had $1.26 billion of outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.5 billion revolving credit facility (the “Sunoco LP Credit Facility”), which expires in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. As of June 30, 2016, the Sunoco LP Credit Facility had $675 million of outstanding borrowings and $22 million in standby letters of credit.

Bakken Financing

In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”). The $2.50 billion facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects.

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 June 30, 2016.

8. EQUITY

ETE

The changes in ETE common units and Convertible Units during the six months ended June 30,2016 were as follows:

	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2015	—	1,044.8
Issuance of Series A Convertible Preferred Units	329.3	—
Outstanding at June 30, 2016	329.3	1,044.8

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Series A Convertible Preferred Units

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.

The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $59 million carrying value as of June 30, 2016.

ETE issued 329,299,267 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.

Repurchase Program

During the six months endedJune 30, 2016, ETE did not repurchase any ETE common units under its current buyback program. As of June 30, 2016, $936 million remained available to repurchase under the current program.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the six months ended June 30, 2016, we recognized decreases in partners’ capital of $12 million.

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ETP Common Unit Transactions

During thesix months ended June 30,2016, ETP received proceeds of $324 million, net of $3 million commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of June 30, 2016, approximately none of ETP’s common units were available to be issued under an equity distribution agreement. In July 2016, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.50 billion.

During the six months ended June 30,2016, distributions of $84 million were reinvested under ETP’s distribution reinvestment plan resulting in the issuance of 3.1 million common units. As of June 30, 2016, a total of 8.4 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment plan.

Sunoco Logistics Common Unit Transactions

During the six months endedJune 30, 2016, Sunoco Logistics received proceeds of $667 million, net of commissions of $7 million, from the issuance of Sunoco Logistics common units pursuant to equity distribution agreements, which were used for general partnership purposes.

Sunoco LP Common Unit Transactions

In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.

In March 2016, ETP contributed to Sunoco LP its remaining68.42%interest in Sunoco, LLC and100%interest in the legacy Sunoco, Inc. retail business for$2.23 billion. Sunoco LP paid$2.20 billionin cash, including a working capital adjustment, and issued5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.

On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.

Bakken Equity Sale

In August 2016, ETP and Sunoco Logistics announced they have signed an agreement to sell 36.75% of the Bakken Pipeline project to MarEn Bakken Company LLC, an entity jointly owned by Enbridge Energy Partners, L.P. and Marathon Petroleum Corporation, for $2.00 billion in cash. The sale is expected to close in the third quarter of 2016, subject to certain closing conditions. ETP and Sunoco Logistics will receive $1.20 billion and $800 million in cash at closing, respectively, and will own a combined 38.25% of the Bakken Pipeline project.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 4, 2016	February 19, 2016	$	0.2850
March 31, 2016	May 6, 2016	May 19, 2016	0.2850
June 30, 2016	August 8, 2016	August 19, 2016	0.2850

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 16, 2016	$	1.0550
March 31, 2016	May 6, 2016	May 16, 2016	1.0550
June 30, 2016	August 8, 2016	August 15, 2016	1.0550

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In July 2016, ETE agreed to relinquish incentive distributions over seven quarters, beginning with $75 millionfor the quarter ended June 30, 2016. ETE has also previously agreed to relinquish additional incentive distributions. In the aggregate, including relinquishment agreed to in July 2016, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units.

	Total Year
2016 (remainder)	$	249
2017	593
2018	105
2019	95

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 12, 2016	$	0.4790
March 31, 2016	May 9, 2016	May 13, 2016	0.4890
June 30, 2016	August 8, 2016	August 12, 2016	0.5000

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 5, 2016	February 16, 2016	$	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255

Accumulated Other Comprehensive Income

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

	June 30, 2016			December 31, 2015
Available-for-sale securities	$	5		$	—
Foreign currency translation adjustment	(5		)	(4		)
Actuarial loss related to pensions and other postretirement benefits	5			8
Investments in unconsolidated affiliates, net	(11		)	—
Subtotal	(6		)	4
Amounts attributable to noncontrolling interest	6			(4		)
Total AOCI, net of tax	$	—		$	—

9. INCOME TAXES

For the three and six months endedJune 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries. Also, for the three months ended June 30, 2015, the Partnership income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015.

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10. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchasers. In June 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement.  As of June 30, 2016, ETP continued to provide contingent, residual support of approximately $1 billion of borrowings.

ETP Retail Holdings Guarantee of Sunoco LP Notes

Retail Holdings has provided a guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion of borrowings outstanding under Sunoco LP’s Term Loan.

NGL Pipeline Regulation

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

FERC Audit

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

Commitments

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Rental expense(1)	$	57		$	54		$	108		$	106
Less: Sublease rental income	(5		)	(4		)	(12		)	(12		)
Rental expense, net	$	52		$	50		$	96		$	94

⁽¹⁾  Includes contingent rentals totaling $7 million and $6 million for the three months ended June 30,2016 and 2015, respectively, and $9 million and $10 million for the six months ended June 30,2016 and 2015, respectively.

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

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Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business.  Natural gas and crude oil are flammable and combustible.  Serious personal injury and significant property damage can arise in connection with their transportation, storage or use.  In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage.  We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry.  However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

Mont Belvieu Incident

On June 26, 2016, a subsurface release of hydrocarbons and water, and a subsequent fire, occurred at Lone Star’s South Terminal.  All employees and contractors were accounted for, and there were no injuries. The cause of the fire and evaluation of possible damages is currently under investigation.

MTBE Litigation

Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater.  The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities.  The plaintiffs primarily assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices.  The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As ofJune 30, 2016, Sunoco, Inc. is a defendant infivecases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action.Fourof these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.

Fact discovery has concluded with respect to an initial set of19sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. The initial set of19 New Jersey trial sites are now pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. Sunoco informed Judge Goodman it is open to participating in global settlement discussions in a global mediation forum. The remaining portion of the New Jersey case remains in the MDL. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency Merger, purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware. The lawsuit alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ Answering Brief is currently due on July 29, 2016.

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Jamie Welch Litigation

On March 10, 2016, Jamie Welch (“Welch”) filed an original petition against ETE and LE GP, LLC (“LE GP”) in Texas state court in Dallas. Welch alleges that Defendants 1) breached their contractual obligation to deliver and convert Welch’s Class D units upon termination; 2) failed to deliver long term incentive shares awarded to Welch; 3) failed to pay Welch’s 2015 bonus; 4) breached their obligation to grant Welch an interest in the Lake Charles LNG project; and 5) breached their obligation to pay Welch his severance. Welch brings claims for breach of contract and quantum meruit. On April 12, 2016, Defendants removed Welch’s lawsuit from state court to federal court in Dallas pursuant to 28 U.S.C. §§ 1441 and 1446. On April 29, 2016, Welch filed an amended complaint and removed his claim for payment of severance benefits.

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

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

Litigation Filed By or Against WMB

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

During a hearing on April 14, 2016, the Court granted WMB’s request to expedite the case and set a permanent injunction hearing for June 15, 2016.

On the same day that it filed the First Delaware WMB Litigation, WMB also filed a petition against Mr. Warren individually in the District Court of Dallas County, Texas (the “Texas WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Kelcy L. Warren, C.A. No. DC-16-03941. Mr. Warren sought dismissal of this lawsuit on the ground that WMB violated the Merger Agreement’s mandatory forum selection clause by filing the Texas WMB Litigation in Texas and not Delaware. On May 25, 2016, the Dallas court granted Mr. Warren’s motion and dismissed the Texas WMB Litigation without prejudice.

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

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

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

After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’s requests for injunctive relief. WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., No. 330, 2016. WMB’s initial appellate brief is due on August 11, 2016.

ETE intends to pursue its counterclaims, including its claim that WMB modified or qualified its board recommendation, which would entitle ETE to a termination fee of $1.48 billion if ETE were successful in proving that claim. ETE also intends to seek damages for WMB’s other breaches of the Merger Agreement.

Litigation Relating to the WMB Merger

Between October 5, 2015, and December 24, 2015, purported WMB stockholders filed six putative class action lawsuits in the Delaware Court of Chancery challenging the merger. The suits are captioned Greenwald et al. v. The Williams Companies, Inc., et al., C.A. No. 11573-VCG; Ozaki v. Armstrong et al., C.A. No. 11574-VCG; Blystone v. The Williams Companies, Inc., et al., C.A. No. 11601-VCG; Glener et al. v. The Williams Companies, Inc., et al., C.A. No. 11606-VCG; Amaitis et al. v. Armstrong et al., C.A. No. 11809-VCG; and State-Boston Retirement System et al. v. Armstrong et al., C.A. No. 11844-VCG. The complaints assert various claims against the individual members of WMB’s board of directors; ETE, ETC, ETC GP, LE GP and ETE GP (the “ETE Defendants”); WMB; and others. On January 13, 2016, the Court consolidated these six actions into a new consolidated action captioned In re The Williams Companies, Inc. Merger Litigation, Consolidated C.A. No. 11844-VCG (the “Merger Litigation”). In its stipulated order, the Court dismissed without prejudice the ETE Defendants (among others) from the consolidated action.

On January 14, 2016, a purported WMB stockholder (“Bumgarner”) filed a putative class action lawsuit against WMB and ETE, captioned Bumgarner v. The Williams Companies, Inc., et al., Case No. 16-cv-26-GKF-FHM, in the United States District Court for the Northern District of Oklahoma. Bumgarner alleged that ETE and WMB violated Section 14 of the Securities Exchange Act of 1934 (the “Exchange Act”) by making allegedly false statements concerning the merger. As relief, the complaint sought an injunction against the proposed merger. On February 1, 2016, Bumgarner filed an amended complaint, making substantially the same allegations. On February 19, 2016, ETE and WMB moved to dismiss the amended complaint. Bumgarner moved for expedited discovery on April 21, 2016. On April 28, 2016, the Court granted the motion to dismiss and dismissed Bumgarner’s claims in their entirety with leave to amend. The Court also granted expedited proceedings. Bumgarner amended his complaint on May 12, 2016, and ETE and WMB again moved to dismiss. The Court granted the motion in part and denied it in part on May 26, 2016, and Bumgarner amended his complaint the same day. Following a motion to reconsider filed by ETE and WMB, the Court revised its Order on the motion to dismiss on June 3, 2016. Bumgarner filed a second motion for a preliminary injunction on June 10, 2016. On June 16, 2016, the parties reached a settlement agreement, and Bumgarner withdrew his motion for a preliminary injunction. Pursuant to the agreement, WMB issued a press release and agreed to provide an updated disclosure to its proxy statement in connection with the merger. WMB also agreed to pay Bumgarner’s attorney fees. On July 28, 2016, Bumgarner’s claim was dismissed with prejudice.

On January 19, 2016, The City of Birmingham Retirement and Relief System (“CBRRS”), a purported shareholder of WMB, filed a putative class action lawsuit against the members of WMB’s board of directors, WMB, ETE, ETC, ETC GP, LE GP, and ETE GP challenging the merger and the disclosures made in connection with the merger. The lawsuit was styled City of Birmingham Retirement and Relief System v. Alan S. Armstrong, et al., C.A. No. 16-17-RGA, in the United States District Court for the District of Delaware. CBRRS alleged violations of Section 14(a) and 20(a) of the Exchange Act among other claims. CBRRS moved to expedite, and Defendants moved to dismiss the suit. The Court denied expedition. CBRRS voluntarily dismissed the suit on March 7, 2016.

Unitholder Litigation Relating to the Issuance

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against, Energy Transfer Equity, L.P. and LE GP, LLC, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery. These lawsuits have

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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. One of the Issuance Plaintiffs had initially filed an action to inspect the books and records of ETE on April 11, 2016 but voluntarily dismissed the books and records action on April 22, 2016.

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

One of the Issuance Plaintiffs moved for expedited proceedings. The Delaware Court of Chancery granted a Motion to Expedite filed by one of the Issuance Plaintiffs and stated that the injunction hearing should be held before any August 2016 distribution. Defendants intend to vigorously defend this consolidated lawsuit.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of June 30, 2016 and December 31, 2015, accruals of approximately $59 million and $40 million, respectively, were reflected on our balance sheets related to these contingent obligations.  As new information becomes available, our estimates may change.  The impact of these changes may have a significant effect on our results of operations in a single period.

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

No amounts have been recorded in our June 30, 2016 or December 31, 2015 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Attorney General of the Commonwealth of Massachusetts v. New England Gas Company.

On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Compliance Orders from the New Mexico Environmental Department

Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

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Lone Star NGL Fractionators Notice of Enforcement

Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to its Mont Belvieu Gas Plant. The Partnership has accrued $300,000 related to the claim. As of April 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 penalty and a $21,000 Supplemental Environmental Project.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites.  Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products.  As a result, there can be no assurance that significant costs and liabilities will not be incurred.  Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits.  Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

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

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

Environmental Remediation

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

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

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

• Currently operating Sunoco, Inc. retail sites.

• Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include 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 identifiedas a potentially responsible party (“PRP”).  As of June 30, 2016, Sunoco, Inc. had been named as a PRP at approximately 49 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law.  Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site.  Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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

	June 30, 2016		December 31, 2015
Current	$	42	$	42
Non-current	323		326
Total environmental liabilities	$	365	$	368

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

During the three months ended June 30,2016 and 2015, Sunoco, Inc. and Sunoco LP collectively recorded $11 million and $11 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30,2016 and 2015, Sunoco, Inc. and Sunoco LP recorded $19 million and $18 million, respectively, of expenditures related to environmental cleanup programs.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period.  On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued an 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 that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.  Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.”  Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis.  Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

In January 2012, Sunoco Logistics experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco Logistics is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco Logistics also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco Logistics has also received a "No Further Action" approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, Sunoco Logistics received a proposed penalty from the EPA and U.S. Department of Justice associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.

Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees.  In addition, OSHA’s hazardous communication standard requires that information be

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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 operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

11. DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

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

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

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

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

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

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

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment. These contracts are not designated as hedges for accounting purposes.

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

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The following table details our outstanding commodity-related derivatives:

	June 30, 2016			December 31, 2015
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	5,825,000		2016-2017	(602,500	)	2016-2017
Basis Swaps IFERC/NYMEX (1)	7,920,000		2016-2017	(31,240,000	)	2016-2017
Power (Megawatt):
Forwards	272,164		2016-2017	357,092		2016-2017
Futures	(320,257	)	2016-2017	(109,791	)	2016
Options — Puts	(424,000	)	2016	260,534		2016
Options — Calls	696,000		2016	1,300,647		2016
Crude (Bbls):
Futures	(222,000	)	2016-2017	(591,000	)	2016-2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(522,500	)	2016-2017	(6,522,500	)	2016-2017
Swing Swaps IFERC	34,465,000		2016-2017	71,340,000		2016-2017
Fixed Swaps/Futures	(3,835,000	)	2016-2018	(14,380,000	)	2016-2018
Forward Physical Contracts	3,838,458		2016-2017	21,922,484		2016-2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(10,443,400	)	2016	(8,146,800	)	2016-2018
Refined Products (Bbls) — Futures	(1,784,000	)	2016-2017	(1,289,000	)	2016-2017
Corn (Bushels) — Futures	(1,635,000	)	2016	1,185,000		2016
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(42,167,500	)	2016-2017	(37,555,000	)	2016
Fixed Swaps/Futures	(42,167,500	)	2016-2017	(37,555,000	)	2016
Hedged Item — Inventory	42,167,500		2016-2017	37,555,000		2016

⁽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 floating rate debt. We also manage our interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and floating 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)	June 30, 2016		December 31, 2015
July 2016(2)(4)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	200
July 2017(3)(4)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	500		300
July 2018(3)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300
July 2019(3)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200

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

⁽²⁾  Represents the effective date. These forward-starting swaps have a term of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million.  In June 2016, ETP extended the expiration of those swaps to July 2017. 

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
	June 30, 2016		December 31, 2015		June 30, 2016			December 31, 2015
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	38	$	(4	)	$	(3	)
	—		38		(4		)	(3		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	138	$	353	$	(173	)	$	(306	)
Commodity derivatives	55		63		(57		)	(47		)
Interest rate derivatives	29		—		(9		)	(171		)
Embedded derivatives in the ETP Preferred Units	—		—		(358		)	(5		)
	222		416		(597		)	(529		)
Total derivatives	$	222	$	454	$	(601	)	$	(532	)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	June 30, 2016			December 31, 2015			June 30, 2016			December 31, 2015
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	29		$	—		$	(367	)	$	(176	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	55			63			(57		)	(47		)
Broker cleared derivative contracts	Other current assets	138			391			(177		)	(309		)
Total gross derivatives		222			454			(601		)	(532		)
Less offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(28		)	(17		)	28			17
Payments on margin deposit	Other current assets	(138		)	(309		)	138			309
Total net derivatives		$	56		$	128		$	(435	)	$	(206	)

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:

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	—	$	—	$	—	$	1
Total	$	—	$	—	$	—	$	1

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2016		2015		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	21	$	11	$	17	$	8
Total		$	21	$	11	$	17	$	8

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2016			2015			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading	Cost of products sold	$	(7	)	$	(6	)	$	(16	)	$	(8	)
Commodity derivatives —Non-trading	Cost of products sold	(53		)	(40		)	(45		)	(48		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(81		)	127			(151		)	50
Embedded derivatives	Other, net	(4		)	2			(4		)	4
Total		$	(145	)	$	83		$	(216	)	$	(2	)

12. RELATED PARTY TRANSACTIONS

The Parent Company has agreements with subsidiaries to provide or receive various management and general and administrative services. The Parent Company pays ETP to provide services on its behalf and on behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

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

In addition, ETE recorded sales with affiliates of $45 million and $130 million during the three months endedJune 30, 2016 and 2015, respectively, and $126 million and $206 million during the six months endedJune 30, 2016 and 2015, respectively.

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13.    REPORTABLE SEGMENTS

Our financial statements reflect the following reportable business segments:

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

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

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

• Corporate and Other, including the following:

• activities of the Parent Company; and

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

The Investment in Sunoco LP segment reflects the results of Sunoco LP and the legacy Sunoco, Inc. retail business for the periods presented. ETE’s consolidated results reflect the elimination of Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.

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

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

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The following tables present financial information by segment:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Segment Adjusted EBITDA:
Investment in ETP	$	1,370		$	1,488		$	2,782		$	2,854
Investment in Sunoco LP	164			142			323			271
Investment in Lake Charles LNG	44			49			88			98
Corporate and Other	(68		)	(25		)	(105		)	(48		)
Adjustments and Eliminations	(125		)	(142		)	(125		)	(271		)
Total	1,385			1,512			2,963			2,904
Depreciation, depletion and amortization	(588		)	(514		)	(1,150		)	(1,007		)
Interest expense, net	(450		)	(408		)	(877		)	(779		)
Gains (losses) on interest rate derivatives	(81		)	127			(151		)	50
Non-cash unit-based compensation expense	(22		)	(25		)	(23		)	(48		)
Unrealized losses on commodity risk management activities	(24		)	(44		)	(84		)	(119		)
Losses on extinguishments of debt	—			(33		)	—			(33		)
Inventory valuation adjustments	181			184			168			150
Equity in earnings of unconsolidated affiliates	95			117			156			174
Adjusted EBITDA related to unconsolidated affiliates	(127		)	(215		)	(346		)	(361		)
Other, net	46			15			40			18
Income before income tax benefit	$	415		$	716		$	696		$	949

	June 30, 2016			December 31, 2015
Assets:
Investment in ETP	$	66,041		$	65,173
Investment in Sunoco LP	8,762			8,842
Investment in Lake Charles LNG	1,437			1,369
Corporate and Other	656			638
Adjustments and Eliminations	(2,336		)	(4,833		)
Total assets	$	74,560		$	71,189

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	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues:
Investment in ETP:
Revenues from external customers	$	5,245		$	11,540		$	9,679		$	21,866
Intersegment revenues	44			—			91			—
	5,289			11,540			9,770			21,866
Investment in Sunoco LP:
Revenues from external customers	4,050			5,126			7,249			9,477
Intersegment revenues	2			—			5			—
	4,052			5,126			7,254			9,477
Investment in Lake Charles LNG:
Revenues from external customers	49			54			98			108
Adjustments and Eliminations	(46		)	(5,126		)	(96		)	(9,477		)
Total revenues	$	9,344		$	11,594		$	17,026		$	21,974

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Intrastate Transportation and Storage	$	428	$	486	$	874	$	1,027
Interstate Transportation and Storage	229		239		483		510
Midstream	690		767		1,217		1,516
Liquids Transportation and Services	1,099		783		1,928		1,595
Investment in Sunoco Logistics	2,250		3,120		3,979		5,646
Retail Marketing	—		5,557		—		10,339
All Other	593		588		1,289		1,233
Total revenues	5,289		11,540		9,770		21,866
Less: Intersegment revenues	44		—		91		—
Revenues from external customers	$	5,245	$	11,540	$	9,679	$	21,866

Investment in Sunoco LP

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Retail operations	$	2,019	$	2,259	$	3,693	$	4,155
Wholesale operations	2,033		2,867		3,561		5,322
Total revenues	4,052		5,126		7,254		9,477
Less: Intersegment revenues	2		—		5		—
Revenues from external customers	$	4,050	$	5,126	$	7,249	$	9,477

Investment in Lake Charles LNG

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

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14. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION

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

BALANCE SHEETS

(unaudited)

	June 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	1
Accounts receivable from related companies	41			34
Other current assets	1			—
Total current assets	43			35
Property, plant and equipment, net	35			20
Advances to and investments in unconsolidated affiliates	5,074			5,764
Intangible assets, net	3			6
Goodwill	9			9
Other non-current assets, net	10			10
Total assets	$	5,174		$	5,844
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	1		$	—
Accounts payable to related companies	58			111
Interest payable	66			66
Accrued and other current liabilities	13			1
Total current liabilities	138			178
Long-term debt, less current maturities	6,362			6,332
Note payable to related company	353			265
Other non-current liabilities	2			1
Commitments and contingencies
Partners’ capital:
General Partner	(2		)	(2		)
Limited Partners:
Common Unitholders	(1,738		)	(952		)
Class D Units	—			22
Series A Convertible Preferred Units	59			—
Total partners’ capital (deficit)	(1,681		)	(932		)
Total liabilities and partners’ capital	$	5,174		$	5,844

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STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(44	)	$	(29	)	$	(81	)	$	(57	)
OTHER INCOME (EXPENSE):
Interest expense, net	(82		)	(72		)	(163		)	(133		)
Equity in earnings of unconsolidated affiliates	369			398			799			771
Other, net	(2		)	—			(2		)	1
INCOME BEFORE INCOME TAXES	241			297			553			582
Income tax benefit	—			(1		)	—			—
NET INCOME	241			298			553			582
General Partner’s interest in net income	1			—			2			1
Convertible Unitholders’ interest in income	1			—			1			—
Class D Unitholder’s interest in net income	—			—			—			1
Limited Partners’ interest in net income	$	239		$	298		$	550		$	580

⁽¹⁾  Includes management fees paid by ETE to ETP.

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STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
	2016			2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	507		$	475
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	—			(817		)
Contributions to unconsolidated affiliate	(65		)	—
Capital expenditures	(15		)	(7		)
Net cash used in investing activities	(80		)	(824		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	145			2,972
Principal payments on debt	(120		)	(1,915		)
Proceeds from affiliate	88			106
Distributions to partners	(540		)	(509		)
Units repurchased under buyback program	—			(294		)
Debt issuance costs	—			(12		)
Net cash provided by (used in) financing activities	(427		)	348
DECREASE IN CASH AND CASH EQUIVALENTS	—			(1		)
CASH AND CASH EQUIVALENTS, beginning of period	1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	1

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

AND RESULTS OF OPERATIONS

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

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC on February 29, 2016. 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, 2015 and “Part II — Item 1A. Risk Factors,” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 and in this Quarterly Report on Form 10-Q for the quarter ended June 30, 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.

OVERVIEW

At June 30, 2016, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 2.6 million ETP common units, 81.0 million ETP Class H units and 2.2 million Sunoco LP common units held by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP.

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

WMB Merger

On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above.

WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.

Series A Convertible Preferred Units

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders who are “accredited investors” (as defined in Regulation D promulgated under the Securities Act ) (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016 and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii),

36

“Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56 stated in the agreement.

The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period.

ETE issued 329,299,267 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.

Bakken Financing

In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects.

Bakken Equity Sale

In August 2016, ETP and Sunoco Logistics announced they have signed an agreement to sell 36.75% of the Bakken Pipeline project to MarEn Bakken Company LLC, an entity jointly owned by Enbridge Energy Partners, L.P. and Marathon Petroleum Corporation, for $2.00 billion in cash. The sale is expected to close in the third quarter of 2016, subject to certain closing conditions. ETP and Sunoco Logistics will receive $1.20 billion and $800 million in cash at closing, respectively, and will own a combined 38.25% of the Bakken Pipeline project.

Quarterly Cash Distribution

In July 2016, ETE announced its quarterly distribution of $0.285 per unit ($1.14 annualized) on ETE common units for the quarter ended June 30, 2016.

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.

37

Based on the change in our reportable segments, we have adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation. In July 2015, ETE obtained control of Sunoco LP from ETP; therefore, the Investment in Sunoco LP amounts have been retrospectively adjusted.

Consolidated Results

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,370		$	1,488		$	(118	)	$	2,782		$	2,854		$	(72	)
Investment in Sunoco LP	164			142			22			323			271			52
Investment in Lake Charles LNG	44			49			(5		)	88			98			(10		)
Corporate and Other	(68		)	(25		)	(43		)	(105		)	(48		)	(57		)
Adjustments and Eliminations	(125		)	(142		)	17			(125		)	(271		)	146
Total	1,385			1,512			(127		)	2,963			2,904			59
Depreciation, depletion and amortization	(588		)	(514		)	(74		)	(1,150		)	(1,007		)	(143		)
Interest expense, net	(450		)	(408		)	(42		)	(877		)	(779		)	(98		)
Gains (losses) on interest rate derivatives	(81		)	127			(208		)	(151		)	50			(201		)
Non-cash unit-based compensation expense	(22		)	(25		)	3			(23		)	(48		)	25
Unrealized losses on commodity risk management activities	(24		)	(44		)	20			(84		)	(119		)	35
Losses on extinguishments of debt	—			(33		)	33			—			(33		)	33
Inventory valuation adjustments	181			184			(3		)	168			150			18
Equity in earnings of unconsolidated affiliates	95			117			(22		)	156			174			(18		)
Adjusted EBITDA related to unconsolidated affiliates	(127		)	(215		)	88			(346		)	(361		)	15
Other, net	46			15			31			40			18			22
Income before income tax benefit	415			716			(301		)	696			949			(253		)
Income tax benefit	(9		)	(56		)	47			(64		)	(44		)	(20		)
Net income	$	424		$	772		$	(348	)	$	760		$	993		$	(233	)

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months and six months ended June 30, 2016 compared to the same periods last year increased primarily due to additional depreciation and amortization from assets recently placed in service.

Interest Expense, Net. Interest expense for the three months and six months ended June 30, 2016 increased primarily due to the following:

• an increase of $29 million and $49 million, respectively, of expense recognized by Sunoco LP primarily due to term loan borrowings, the issuance of senior notes, and an increase in borrowings under the Sunoco LP revolving credit facility; and

• an increase of $10 million and $30 million, respectively, of expense recognized by the Parent Company primarily related to the May 2015 issuance of $1 billion aggregate principal amount of its 5.5 % senior notes, higher average outstanding borrowings on the ETE Senior Secured Term Loan during the current period and higher average interest rates during the current period.

Gains (Losses) on Interest Rate Derivatives. Losses on interest rate derivatives during the three and six months endedJune 30, 2016 were primarily attributable to the impact on our forward starting swap locks from the downward shift in the forward LIBOR

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curve. The gains reflected for the three and six months ended June 30, 2015 resulted from increases in forward interest rates, which caused our forward-starting swaps to increase in value.

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

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded during the three months and six months ended June 30, 2016 and 2015, for the inventory associated with Sunoco LP and Sunoco Logistics as a result of commodity price changes between periods.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. Amounts reflected primarily include our proportionate share of such amounts related to AmeriGas, FEP, HPC, MEP, PES and Citrus.

Other, net. Includes amortization of regulatory assets, certain acquisition related costs and other income and expense amounts.

Income Tax Benefit. For the For the three and six months endedJune 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries. Also, for the three months ended June 30, 2015, the Partnership income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015.

Segment Operating Results

Investment in ETP

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
Revenues	$	5,289		$	11,540		$	(6,251	)	$	9,770		$	21,866		$	(12,096	)
Cost of products sold	3,630			9,354			(5,724		)	6,598			17,850			(11,252		)
Gross margin	1,659			2,186			(527		)	3,172			4,016			(844		)
Unrealized losses on commodity risk management activities	18			42			(24		)	81			119			(38		)
Operating expenses, excluding non-cash compensation expense	(375		)	(636		)	261			(723		)	(1,247		)	524
Selling, general and administrative, excluding non-cash compensation expense	(78		)	(160		)	82			(163		)	(294		)	131
Inventory valuation adjustments	(132		)	(184		)	52			(106		)	(150		)	44
Adjusted EBITDA related to unconsolidated affiliates	252			215			37			471			361			110
Other	26			25			1			50			49			1
Segment Adjusted EBITDA	$	1,370		$	1,488		$	(118	)	$	2,782		$	2,854		$	(72	)

Segment Adjusted EBITDA. For the three months ended June 30, 2016 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP decreased due to the net impact of the following:

• a decrease of $81 million from Sunoco Logistics due to a decrease of $49 million from Sunoco Logistics’ crude oil operations largely attributable to lower operating results from Sunoco Logistics’ crude oil acquisition and marketing activities, a decrease of $51 million from Sunoco Logistics’ NGLs operations, primarily due to lower results from Sunoco Logistics’ NGLs acquisition and marketing activities, offset by an increase of $19 million from Sunoco Logistics’ refined products operations, primarily due to improved operating results from Sunoco Logistics’ refined products pipelines and terminals;

• a decrease of $72 million in ETP’s retail marketing operations as a result of ETP’s transfer of the general partner interest of Sunoco LP to ETE in 2015 and the completion of the contribution of remaining retail marketing operations from ETP to Sunoco LP in March 2016;

• a decrease of $54 million in ETP’s midstream operations primarily due to a $63 million impact from settled derivatives used to hedge commodity margins, a $10 million decrease due to lower natural gas, crude and NGL prices, and an $8

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million increase in operating expenses due to assets recently placed in service. These decreases were partially offset by an increase of $15 million in gross margin from assets recently placed in service and lower midstream general and administrative expenses of $11 million due to lower allocated costs;

• a decrease of approximately $2 million in ETP’s all other operations, primarily due to the impact of refining crack spreads on ETP’s investment in PES; offset by

• an increase of $66 million in ETP’s liquids transportation and services operations, primarily attributable to higher volumes transported out of all major producing regions, including the Permian, North Texas, Southeast Texas, Eagle Ford, and Louisiana, along with the impact of favorable market conditions and the ramp-up of the third fractionator at Mont Belvieu; and

• an increase of $32 million in ETP’s intrastate transportation and storage operations due to an increase in realized margin on natural gas inventory transactions.

For the six months ended June 30, 2016 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP decreased primarily due to the net impact of the following:

• a decrease of $144 million in ETP’s retail marketing operations as a result of ETP’s transfer of the general partner interest of Sunoco LP to ETE in 2015 and the completion of the contribution of remaining retail marketing operations from ETP to Sunoco LP in March 2016;

• a decrease of $101 million in ETP’s midstream operations primarily due to an $85 million decrease in gross margin due to lower benefit from settled derivatives used to hedge commodity margins, a $42 million decrease due to lower natural gas, crude and NGL prices, and a $15 million increase in operating assets due to assets recently placed in service. These decreases were partially offset by an increase of $35 million in gross margin from assets recently placed in service, lower midstream general and administrative expenses of $2 million due to lower allocated costs, and an increase of $4 million due to higher volumes through ETP’s midstream joint ventures;

• a decrease of $16 million in ETP’s interstate transportation and storage operations, primarily attributable to the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service, the expiration of a transportation rate schedule on the Transwestern pipeline, a contract restructuring on the Tiger pipeline, and reduced gas supply on the Sea Robin pipeline;

• a decrease of approximately $16 million in ETP’s all other operations, primarily due to unfavorable results from the natural resources operations; offset by

• an increase of $124 million in ETP’s liquids transportation and services operations, primarily attributable to higher volumes transported out of all major producing regions, including the Permian, North Texas, Southeast Texas, Eagle Ford, and Louisiana, along with the impact of favorable market conditions and the ramp-up of the third fractionator at Mont Belvieu;

• an increase of $47 million from Sunoco Logistics due to an increase of $15 million from Sunoco Logistics’ crude oil operations due to improved results from Sunoco Logistics’ crude oil pipelines, a decrease of $5 million from Sunoco Logistics’ NGLs operations, primarily due to lower volumes and margins from Sunoco Logistics’ NGLs acquisition and marketing activities largely offset by increased volumes and fees from Sunoco Logistics’ Mariner NGLs projects, offset by an increase of $37 million from Sunoco Logistics’ refined products operations, primarily due to increased operating results from Sunoco Logistics’ refined products pipelines and terminals; and

• an increase of $34 million in ETP’s intrastate transportation and storage operations primarily due to an increase in realized margin on natural gas inventory transactions.

Unrealized Losses on Commodity Risk Management Activities. Unrealized losses on commodity risk management activities primarily reflected the net impact from unrealized gains and losses on natural gas storage and non-storage derivatives, as well as fair value adjustments to inventory. For the three and six months ended June 30, 2016 compared to the same periods last year, the changes included decreases of $71 million and $82 million, respectively, related to ETP’s midstream operations and $4 million and $6 million, respectively, related to Sunoco Logistics. These were partially offset by increases of $27 million and $30 million, respectively, related to ETP’s intrastate transportation and storage operations and $11 million and $11 million, respectively, related to ETP’s liquids transportation and services operations.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and six months ended June 30,2016 compared to the same periods last year, ETP’s operating expenses decreased $261 million and $524 million, respectively, primarily due to ETP’s deconsolidation of Sunoco LP and the remainder of its retail marketing operations.

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Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three and six months ended June 30,2016 compared to the same periods last year, ETP’s selling, general and administrative expenses decreased $82 million and $131 million, respectively, primarily due to ETP’s deconsolidation of Sunoco LP and the remainder of its retail marketing operations.

Adjusted EBITDA Related to Unconsolidated Affiliates. Adjusted EBITDA related to unconsolidated affiliates for the three and six months ended June 30, 2016 increased compared to the same period last year primarily due to $68 million and $125 million, respectively, of adjusted EBITDA related to Sunoco LP, which is an equity method investment subsequent to July 1, 2015 as a result of ETP’s deconsolidation.

Investment in Sunoco LP

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
Revenues	$	4,052		$	5,126		$	(1,074	)	$	7,254		$	9,477		$	(2,223	)
Cost of products sold	3,472			4,581			(1,109		)	6,175			8,483			(2,308		)
Gross margin	580			545			35			1,079			994			85
Operating expenses, excluding non-cash compensation expense	(303		)	(285		)	(18		)	(585		)	(561		)	(24		)
Selling, general and administrative, excluding non-cash compensation expense	(70		)	(64		)	(6		)	(112		)	(102		)	(10		)
Inventory fair value adjustments	(49		)	(55		)	6			(62		)	(62		)	—
Unrealized losses on commodity risk management activities	6			1			5			3			2			1
Segment Adjusted EBITDA	$	164		$	142		$	22		$	323		$	271		$	52

The Investment in Sunoco LP segment reflects the results of Sunoco LP for all periods presented. Sunoco LP obtained control of Sunoco, LLC in April 2015, Susser in July 2015 and the legacy Sunoco, Inc. retail business in March 2016. Because these entities were under common control, Sunoco LP recast its financial statements to retrospectively consolidate each of the entities beginning September 1, 2014. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business beginning September 1, 2014. Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business were also consolidated by ETP until April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the six months ended June 30, 2015. ETE’s consolidated results reflect the elimination of Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.

Segment Adjusted EBITDA. The increase in Segment Adjusted EBITDA for the three and six months ended June 30,2016, compared to the same period in the prior year was primarily due to lower cost of motor fuels and an increase in the number of retail sites.

Investment in Lake Charles LNG

	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
Revenues	$	49		$	54		$	(5	)	$	98		$	108		$	(10	)
Operating expenses, excluding non-cash compensation expense	(5		)	(4		)	(1		)	(9		)	(8		)	(1		)
Selling, general and administrative, excluding non-cash compensation expense	—			(1		)	1			(1		)	(2		)	1
Segment Adjusted EBITDA	$	44		$	49		$	(5	)	$	88		$	98		$	(10	)

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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 announced 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.

ETP currently expects capital expenditures in 2016 to be within the following ranges:

	Growth				Maintenance
	Low		High		Low		High
Direct(1):
Intrastate transportation and storage(2)	$	30	$	40	$	20	$	25
Interstate transportation and storage(2)(3)	210		250		105		115
Midstream	1,225		1,275		125		135
Liquids transportation and services:
NGL	975		1,000		20		25
Crude(2)(3)	300		325		—		—
All other (including eliminations)	90		100		40		45
Total direct capital expenditures	$	2,830	$	2,990	$	310	$	345

⁽¹⁾  Direct capital expenditures exclude those funded by our publicly traded subsidiary.

⁽²⁾  Net of amounts forecasted to be financed at the asset level with non-recourse debt of approximately$1.16 billion.

⁽³⁾  Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

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

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.

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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 capital expenditures, excluding acquisitions, in 2016 to be within the following ranges:

	Growth (1)				Maintenance
	Low		High		Low		High
Year ended December 31, 2016	$	380	$	400	$	100	$	110

⁽¹⁾ The above growth capital spending estimate includes at least 35 new-to-industry stores that are planned to be built in 2016.

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.

Six months ended June 30,2016 compared to six months ended June 30,2015. Cash provided by operating activities during 2016 was $1.52 billion as compared to $1.1 billion for 2015. Net income was $760 million and $993 million for 2016 and 2015, respectively. The difference between net income and the net cash provided by operating activities for the six months ended June 30, 2016, primarily consisted of non-cash items totaling $656 million and net changes in operating assets and liabilities of $31 million.

The non-cash activity in 2016 and 2015 consisted primarily of depreciation, depletion and amortization of $1.2 billion and $1.01 billion, respectively, unit-based compensation expense of $23 million and $48 million, respectively, and equity in earnings of unconsolidated affiliates of $156 million and $174 million, respectively. Non-cash activity in 2016 and 2015 also included deferred income taxes of $84 million and $77 million, respectively, and inventory valuation adjustments of $168 million and $150 million, respectively.

Cash paid for interest, net of interest capitalized, was $901 million and $824 million for the six months ended June 30, 2016 and 2015, respectively.

Capitalized interest was $111 million and $69 million for the six months ended June 30, 2016 and 2015, 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.

Six months ended June 30,2016 compared to six months ended June 30,2015. Cash used in investing activities during 2016 was $3.78 billion as compared to $4.67 billion for 2015. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2016 were $3.70 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 2015 of $4.17 billion. During the six months ended June 30, 2015, we paid cash for acquisitions of $475 million, we paid $129 million for the purchase of noncontrolling interest and we received $64 million in proceeds from the sale of noncontrolling interest.

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.

Six months ended June 30,2016 compared to six months ended June 30,2015. Cash provided by financing activities during 2016 was $2.13 billion as compared to $4.34 billion for 2015. In 2016, ETP received $408 million in net proceeds from offerings of their common units as compared to $724 million in 2015. In 2016, Sunoco Logistics received $667 million in net proceeds from offerings of their common units as compared to $1.01 billion in 2015. During 2016, we had a consolidated net increase in our debt level of $2.50 billion as compared to a net increase of $4.17 billion for 2015. We have paid distributions of $540 million and $509 million to our partners in 2016 and in 2015, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $1.34 billion and $1.13 billion in 2016 and 2015, respectively.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	June 30, 2016			December 31, 2015
Parent Company Indebtedness:
ETE Senior Secured Notes	$	3,337		$	3,337
ETE Senior Secured Term Loan, due December 2, 2019	2,190			2,190
ETE Senior Secured Revolving Credit Facility	885			860
Subsidiary Indebtedness:
ETP Senior Notes	19,439			19,439
Panhandle Senior Notes	1,085			1,085
Sunoco, Inc. Senior Notes	465			465
Sunoco Logistics Senior Notes	4,800			4,975
Transwestern Senior Notes	782			782
Sunoco LP Senior Notes	2,200			1,400
Sunoco LP Term Loan	1,243			—
Revolving Credit Facilities:
ETP $3.75 billion Revolving Credit Facility due November 2019	1,128			1,362
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 (1)	1,263			562
Sunoco LP $1.5 billion Revolving Credit Facility due March 2020	675			450
Other Long-Term Debt	152			157
Unamortized premiums and fair value adjustments, net	121			141
Deferred debt issuance costs	(251		)	(237		)
Total	39,514			36,968
Less: Current maturities of long-term debt	1,013			131
Long-term debt and notes payable, less current maturities	$	38,501		$	36,837

⁽¹⁾  Includes $106 million of commercial paper product outstanding at June 30, 2016.

Senior Notes

ETP Senior Notes

Subsequent to the Regency Merger in 2015, ETP assumed $3.80 billion total aggregate principal amount of Regency’s senior notes, which remained outstanding as of June 30, 2016. These notes were previously guaranteed by certain consolidated subsidiaries that had previously been consolidated by Regency. The subsidiary guarantees on all of these outstanding notes have been released.

Sunoco Logistics Senior Notes

Sunoco Logistics had $175 million of 6.125% senior notes which matured and were repaid in May 2016, using borrowings under the $2.50 billion Sunoco Logistics Credit Facility.

In July 2016, Sunoco Logistics issued$550 millionaggregate principal amount of3.90%senior notes due in July 2026. The net proceeds from this offering were used to repay outstanding credit facility borrowings and for general partnership purposes.

Sunoco LP Term Loan and Senior Notes

In March, 2016, Sunoco LP entered into a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. As of June 30, 2016, Sunoco LP had $1.2 billion outstanding under the term loan. Amounts borrowed under the term loan bear interest at either LIBOR or base rate plus an applicable margin based on Sunoco LP’s election for each interest period. The proceeds were used to fund a portion of the ETP dropdown and to pay fees and expenses incurred in connection with the ETP dropdown and the term loan.

In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.

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Revolving Credit Facilities

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.

As of June 30, 2016, we had $885 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $615 million.

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. As of June 30, 2016, the ETP Credit Facility had $1.13 billion of outstanding borrowings.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $2.5 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of June 30, 2016, the Sunoco Logistics Credit Facility had $1.26 billion of outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.5 billion revolving credit facility (the “Sunoco LP Credit Facility”), which expires in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. As of June 30, 2016, the Sunoco LP Credit Facility had $675 million of outstanding borrowings and $22 million in standby letters of credit.

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 June 30, 2016.

CASH DISTRIBUTIONS

Cash Distributions Paid by the Parent Company

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

Following are distributions declared and/or paid by us subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 4, 2016	February 19, 2016	$	0.2850
March 31, 2016	May 6, 2016	May 19, 2016	0.2850
June 30, 2016	August 8, 2016	August 19, 2016	0.2850

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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):

	Six Months Ended June 30,
	2016		2015
Limited Partners	$	480	$	545
General Partner interest	1		1
Class D units	—		1
Total Parent Company distributions	$	481	$	547

Cash Distributions Received by the Parent Company

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

As the holder of ETP’s IDRs, the Parent Company is entitled to an increasing share of ETP’s total distributions above certain target levels. The following table summarizes the target levels (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 H units, Class I units and a portion of the outstanding ETP common units.

	Percentage of Total Distributions to IDRs	Quarterly Distribution Rate Target Amounts
Minimum quarterly distribution	—%	$0.25
First target distribution	—%	$0.25 to $0.275
Second target distribution	13%	$0.275 to $0.3175
Third target distribution	23%	$0.3175 to $0.4125
Fourth target distribution	48%	Above $0.4125

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:

	Six Months Ended June 30,
	2016			2015
Distributions from ETP:
Limited Partner interests	$	5		$	48
Class H Units	171			118
General Partner interest	16			15
IDRs	666			617
IDR relinquishments net of Class I Unit distributions	(144		)	(55		)
Total distributions from ETP	714			743
Distributions from Sunoco LP (1)
Limited Partner interests	4			—
IDRs	40			—
Total distributions from Sunoco LP	44			—
Total distributions received from subsidiaries	$	758		$	743

⁽¹⁾  Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP.

47

In July 2016, ETE agreed to relinquish incentive distributions over seven quarters, beginning with $75 million for the quarter ended June 30, 2016. ETE has also previously agreed to relinquish additional incentive distributions. In the aggregate, including the relinquishment agreed to in July 2016, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units.

	Total Year
2016 (remainder)	$	249
2017	593
2018	105
2019	95

ETE may agree to relinquish its rights to additional amounts of incentive distributions in future periods. Please see “Part I - Item 1A. Risk Factors — ETE may agree to relinquish its rights to a portion of its incentive distributions in future periods without the consent of ETE unitholders” of our Annual Report on Form 10-K for the year ended December 31, 2015.

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 are distributions declared and/or paid by ETP subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 16, 2016	$	1.0550
March 31, 2016	May 6, 2016	May 16, 2016	1.0550
June 30, 2016	August 8, 2016	August 15, 2016	1.0550

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

	Six Months Ended June 30,
	2016			2015
Limited Partners:
Common Units	$	1,058		$	998
Class H Units	171			118
General Partner interest	16			15
IDRs	666			617
IDR relinquishments net of Class I Unit distributions	(144		)	(55		)
Total ETP distributions	$	1,767		$	1,693

Cash Distributions Paid by Sunoco Logistics

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 12, 2016	$	0.4790
March 31, 2016	May 9, 2016	May 13, 2016	0.4890
June 30, 2016	August 8, 2016	August 12, 2016	0.5000

Sunoco Logistics is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by its general partner.

48

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

	Six Months Ended June 30,
	2016		2015
Limited Partners:
Common units held by public	$	223	$	157
Common units held by ETP	66		57
General Partner interest held by ETP	7		6
Incentive distributions held by ETP	183		125
Total distributions declared	$	479	$	345

Cash Distributions Paid by Sunoco LP

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 5, 2016	February 16, 2016	$	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	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):

	Six Months Ended June 30,
	2016		2015
Limited Partners:
Common units held by public	$	81	$	31
Common and subordinated units held by ETP	71		21
Common and subordinated units held by ETE	4		—
General Partner interest and Incentive distributions	40		5
Total distributions declared	$	196	$	57

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, 2015, 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, 2015. Since December 31, 2015, 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.

49

	June 30, 2016							December 31, 2015
	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	5,825,000		$	1		$	2	(602,500	)	$	(1	)	$	—
Basis Swaps IFERC/NYMEX (1)	7,920,000		(3		)	1		(31,240,000	)	(1		)	—
Power (Megawatt):
Forwards	272,164		2			—		357,092		—			2
Futures	(320,257	)	(1		)	1		(109,791	)	2			—
Options — Puts	(424,000	)	—			—		260,534		—			—
Options — Calls	696,000		3			5		1,300,647		—			3
Crude (Bbls):
Futures	(222,000	)	(2		)	4		(591,000	)	4			3
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(522,500	)	1			—		(6,522,500	)	—			—
Swing Swaps IFERC	34,465,000		—			—		71,340,000		(1		)	—
Fixed Swaps/Futures	(3,835,000	)	1			1		(14,380,000	)	(1		)	5
Forward Physical Contracts	3,838,458		2			1		21,922,484		4			5
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(10,443,400	)	(12		)	12		(8,146,800	)	10			13
Refined Products (Bbls) — Futures	(1,784,000	)	(11		)	43		(1,289,000	)	8			11
Corn (Bushels) — Futures	(1,635,000	)	—			1		1,185,000		—			1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(42,167,500	)	3			1		(37,555,000	)	—			—
Fixed Swaps/Futures	(42,167,500	)	(25		)	14		(37,555,000	)	73			9

⁽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 June 30, 2016, we and our subsidiaries had $9.63 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $96 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

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

Term	Type (1)	Notional Amount Outstanding
		June 30, 2016		December 31, 2015
July 2016(2)(4)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	200
July 2017(3)(4)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	500		300
July 2018(3)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300
July 2019(3)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200

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

⁽²⁾  Represents the effective date. These forward-starting swaps have a term of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million.  In June 2016, ETP extended the expiration of those swaps to July 2017. 

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 $251 million as of June 30, 2016. 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 $43 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 June 30, 2016 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 June 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2015 and Note 10 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

ITEM 1A. RISK FACTORS

The following risk factors updated risk factors previously reported and should be read in conjunction with our risk factors described in “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015 and “Part II - Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016.

Litigation commenced by WMB against ETE and its affiliates could cause ETE to incur substantial costs, may present material distractions and, if decided adverse to ETE, could negatively impact ETE’s financial position and credit ratings.

WMB previously filed a complaint against ETE and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates. Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ETE on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. WMB’s Opening Brief is due on August 11, 2016. These lawsuits could result in substantial costs to ETE, including litigation costs and settlement costs. ETE believes that the time required by the management of ETE and its counsel to defend against the allegations made by WMB in the litigation against ETE and its affiliates is likely to be substantial and the time required by the officers and employees of LE GP, assuming WMB actively pursues such litigation, is also likely to be substantial. The defense or settlement of any lawsuit or claim that remains unresolved may result in negative media attention, and may adversely affect ETE’s business, reputation, financial condition, results of operations, cash flows and market price.

The profitability of certain activities in our natural gas gathering, processing, transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.

For a portion of the natural gas gathered on our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.

We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers.

Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements, our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our revenues and results of operations.

Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.

When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.

We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.

In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and

52

fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.

For ETP’s midstream operations, we generally analyze gross margin based on fee-based margin (which includes revenues from processing fee arrangements) and non fee-based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). For the six months ended June 30, 2016 and 2015, gross margin from ETP’s midstream operations totaled $874 million and $883 million, respectively, of which fee-based revenues constituted 88% and 85%, respectively, and non fee-based margin constituted 12% and 15%, respectively. For the years ended December 31, 2015 and 2014, gross margin from ETP’s midstream segment totaled $1.81 billion and $1.93 billion, respectively, of which fee-based revenues constituted 86% and 66%, respectively, and non fee-based margin constituted 14% and 34%, respectively. The amount of gross margin earned by ETP’s midstream operations from fee-based and non fee-based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non fee-based arrangements in future periods may be significantly different from results reported in previous periods.

ITEM 6. EXHIBITS

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

Exhibit Number	Description
Other Exhibits
	Energy Transfer Equity, L.P.
2.1	Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed May 3, 2016).
4.1	Registration Rights Agreement, dated as of March 31, 2016, by and between Sunoco LP and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed April 4, 2016).
	Other Exhibits
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.

53

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:	August 5, 2016	By:	/s/ Thomas E. Long
			Thomas E. Long
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)

54

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 5, 2016

/s/ John W. McReynolds

John W. McReynolds

President

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas E. Long, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 5, 2016

/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 June 30, 2016, 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: August 5, 2016

/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 June 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Long, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

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

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

Date: August 5, 2016

/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	6 Months Ended
	Jun. 30, 2016	Jul. 29, 2016
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	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,044,791,157

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
ASSETS
Cash and cash equivalents	$ 475	$ 606
Accounts receivable, net	2,944	2,400
Accounts receivable from related companies	60	119
Inventories	1,929	1,636
Derivative assets	38	46
Other current assets	644	603
Total current assets	6,090	5,410
Property, plant and equipment	58,663	54,979
Accumulated depreciation and depletion	(7,277)	(6,296)
Property, Plant and Equipment, Net	51,386	48,683
Advances to and investments in unconsolidated affiliates	3,453	3,462
Non-current derivative assets	18	0
Other non-current assets, net	742	730
Intangible assets, net	5,356	5,431
Goodwill	7,515	7,473
Total assets	74,560	71,189
LIABILITIES AND EQUITY
Accounts payable	2,931	2,274
Accounts payable to related companies	20	28
Derivative liabilities	29	69
Accrued and other current liabilities	2,195	2,408
Current maturities of long-term debt	1,013	131
Total current liabilities	6,188	4,910
Long-term debt, less current maturities	38,501	36,837
Note payable to related company	107	0
Deferred income taxes	5,215	4,590
Non-current derivative liabilities	367	137
Other non-current liabilities	1,137	1,069
Commitments and contingencies
Preferred units of subsidiary	33	33
Redeemable noncontrolling interests	15	15
EQUITY:
General Partner	(2)	(2)
Limited Partners:
Common Unitholders	(1,738)	(952)
Class D Units	0	22
Preferred Units, Preferred Partners' Capital Accounts	59	0
Total partners’ capital (deficit)	(1,681)	(932)
Noncontrolling interest	24,678	24,530
Total equity	22,997	23,598
Total liabilities and equity	$ 74,560	$ 71,189

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Consolidated Statements Of Operations - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
REVENUES
Natural gas sales	$ 695	$ 898	$ 1,533	$ 1,933
NGL sales	1,150	988	2,090	1,969
Crude sales	1,714	2,680	2,923	4,888
Gathering, transportation and other fees	1,087	1,035	2,090	2,081
Refined product sales	3,877	4,434	6,416	8,090
Other	821	1,559	1,974	3,013
Total revenues	9,344	11,594	17,026	21,974
COSTS AND EXPENSES
Cost of products sold	7,054	9,338	12,676	17,825
Operating expenses	688	663	1,329	1,291
Depreciation, depletion and amortization	588	514	1,150	1,007
Selling, general and administrative	187	183	343	338
Total costs and expenses	8,517	10,698	15,498	20,461
OPERATING INCOME	827	896	1,528	1,513
OTHER INCOME (EXPENSE)
Interest expense, net	(450)	(408)	(877)	(779)
Equity in earnings of unconsolidated affiliates	95	117	156	174
Losses on extinguishments of debt	0	(33)	0	(33)
Gains (losses) on interest rate derivatives	(81)	127	(151)	50
Other, net	24	17	40	24
INCOME BEFORE INCOME TAX BENEFIT	415	716	696	949
Income tax benefit	(9)	(56)	(64)	(44)
INCOME FROM CONTINUING OPERATIONS	424	772	760	993
NET INCOME	424	772	760	993
Less: Net income attributable to noncontrolling interest	183	474	207	411
NET INCOME ATTRIBUTABLE TO PARTNERS	241	298	553	582
General Partner’s interest in net income	1	0	(2)	(1)
Convertible Unitholders' interest in income	1	0	1	0
Class D Unitholder’s interest in net income	0	0	0	1
Limited Partners’ interest in net income	$ 239	$ 298	$ 550	$ 580
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$ 0.23	$ 0.28	$ 0.53	$ 0.54
Diluted	$ 0.23	$ 0.28	$ 0.52	$ 0.54

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Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 424	$ 772	$ 760	$ 993
Other comprehensive income (loss), net of tax:
Change in value of derivative instruments accounted for as cash flow hedges	0	0	0	1
Change in value of available-for-sale securities	3	(1)	5	0
Actuarial gain (loss) relating to pension and other postretirement benefit plans	6	0	(3)	45
Foreign currency translation adjustments	0	0	(1)	(2)
Change in other comprehensive income from unconsolidated affiliates	(5)	0	(11)	(2)
Other comprehensive income (loss), net of tax	4	(1)	(10)	42
Comprehensive income	428	771	750	1,035
Less: Comprehensive income attributable to noncontrolling interest	187	470	197	450
Comprehensive income attributable to partners	$ 241	$ 301	$ 553	$ 585

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Consolidated Statement Of Equity - 6 months ended Jun. 30, 2016 - USD ($) $ in Millions	Total	General Partner	Common Unitholders	Class D Units	Series A Convertible Preferred Units [Member]	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Balance, December 31, 2015 at Dec. 31, 2015	$ 23,598	$ (2)	$ (952)	$ 22	$ 0	$ 0	$ 24,530
Distributions to partners	(540)	(2)	(538)	0	0	0	0
Distributions to noncontrolling interest	(1,343)	0	0	0	0	0	(1,343)
Partners' Capital Account, Convertible Unit Distributions	0	0	(58)	0	58	0	0
Subsidiary units issued	1,075	0	(12)	0	0	0	1,087
Non-cash compensation expense, net of units tendered by employees for tax withholdings	21	0	0	(22)	0	0	43
Capital contributions received from noncontrolling interest	161	0	0	0	0	0	161
Stock Repurchased During Period, Value	0	0	0	0	0	0	0
Sunoco, Inc. retail business to Sunoco LP transaction	(741)	0	(741)	0	0	0	0
Other comprehensive loss, net of tax	(10)	0	0	0	0	0	(10)
Other, net	16	0	13	0	0	0	3
Net income	760	2	550	0	1	0	207
Balance, June 30, 2016 at Jun. 30, 2016	$ 22,997	$ (2)	$ (1,738)	$ 0	$ 59	$ 0	$ 24,678

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Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
OPERATING ACTIVITIES
Net income	$ 760	$ 993
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,150	1,007
Deferred income taxes	(84)	77
Amortization included in interest expense	(1)	(16)
Unit-based compensation expense	23	48
(Gains) losses on disposal of assets	6	(3)
Losses on extinguishments of debt	0	(33)
Inventory valuation adjustments	(168)	(150)
Equity in earnings of unconsolidated affiliates	(156)	(174)
Distributions from unconsolidated affiliates	133	162
Other non-cash	(114)	22
Net change in operating assets and liabilities, net of effects of acquisition	(31)	(886)
Net cash provided by operating activities	1,518	1,113
INVESTING ACTIVITIES
Cash paid for acquisitions, net of cash received	(116)	(475)
Cash received for sale of noncontrolling interest	0	64
Cash paid for acquisition of a noncontrolling interest	0	(129)
Capital expenditures, excluding allowance for equity funds used during construction	(3,723)	(4,181)
Contributions in aid of construction costs	25	12
Contributions to unconsolidated affiliate	30	43
Distributions from unconsolidated affiliates in excess of cumulative earnings	56	64
Proceeds from the sale of assets	16	15
Change in restricted cash	2	(8)
Other	(1)	(8)
Net cash used in investing activities	(3,775)	(4,673)
FINANCING ACTIVITIES
Proceeds from borrowings	12,048	15,466
Repayments of long-term debt	(9,551)	(11,301)
Subsidiary units issued for cash	1,075	1,773
Distributions to partners	(540)	(509)
Debt issuance costs	(29)	(61)
Distributions to noncontrolling interest	(1,343)	(1,133)
Capital contributions received from noncontrolling interest	161	398
Units repurchased under buyback program	0	294
Other, net	305	(3)
Net cash provided by financing activities	2,126	4,336
Increase (decrease) in cash and cash equivalents	(131)	776
Cash and cash equivalents, beginning of period	606	847
Cash and cash equivalents, end of period	$ 475	$ 1,623

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Operations And Organization

6 Months Ended

Jun. 30, 2016

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.

The consolidated financial statements of ETE presented herein include the results of operations of:

• the Parent Company;

• our controlled subsidiaries, ETP and Sunoco LP;

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

• our wholly-owned subsidiary, Lake Charles LNG.

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

Business Operations

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

Our financial statements reflect the following reportable business segments:

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

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

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

• Corporate and Other, including the following:

• activities of the Parent Company; and

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

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income or total equity.

Use of Estimates

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

Subsidiary Common Unit Transactions

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

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. The Partnership adopted this standard on January 1, 2016, and the adoption did not impact the Partnership’s financial position or results of operations.

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, if any, that adopting this new standard will have on the consolidated financial statements and related disclosures.

In March 2016, the FASB issued 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. In addition, the amendments in this update eliminate the guidance in Topic 718 that was indefinitely deferred shortly after the issuance of FASB Statement No. 123 (revised 2004), Share-Based Payment. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.

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Acquisitions

6 Months Ended

Jun. 30, 2016

ACQUISITIONS AND DIVESTITURE [Abstract]

Acquisitions

ACQUISITIONS AND CONTRIBUTION TRANSACTIONS

WMB Merger

On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above.

WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.

Sunoco Retail to Sunoco LP

In March 2016, ETP contributed to Sunoco LP its remaining68.42%interest in Sunoco, LLC and100%interest in the legacy Sunoco, Inc. retail business for$2.23 billion. Sunoco LP paid$2.20 billionin cash, including a working capital adjustment, and issued5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP. The transaction was effective January 1, 2016.

Other Sunoco LP Acquisitions

In June 2016, Sunoco LP entered into a definitive agreement to purchase the fuels business from Emerge Energy Services LP for $179 million, subject to working capital and other adjustments. The transaction is scheduled to close in the third quarter of 2016, subject to regulatory clearances and the satisfaction of other customary closing conditions. Additionally, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $45 million.

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Cash And Cash Equivalents

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

Cash And Cash Equivalents

CASH AND CASH EQUIVALENTS

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

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

Non-cash investing activities were as follows:

	Six Months Ended June 30,
	2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	881		$	693
Gains (losses) from subsidiary common unit issuances, net	(12		)	50

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Inventories (Notes)

6 Months Ended

Jun. 30, 2016

Inventory, Net [Abstract]

Inventories

INVENTORIES

Inventories consisted of the following:

	June 30, 2016		December 31, 2015
Natural gas and NGLs	$	552	$	415
Crude oil	564		424
Refined products	452		420
Other	361		377
Total inventories	$	1,929	$	1,636

We utilize commodity derivatives to manage price volatility associated with our 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

6 Months Ended

Jun. 30, 2016

Fair Value Measurements [Abstract]

Fair Value Measurements

FAIR VALUE MEASURES

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2016 was $39.84 billion and $39.51 billion, respectively. As of December 31, 2015, the aggregate fair value and carrying amount of our consolidated debt obligations was $33.22 billion and $36.97 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in the preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the six months endedJune 30, 2016, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2016 and December 31, 2015 based on inputs used to derive their fair values:

	Fair Value Measurements at June 30, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	29		$	—		$	29		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	18			18			—			—
Swing Swaps IFERC	6			—			6			—
Fixed Swaps/Futures	41			41			—			—
Forward Physical Swaps	4			—			4			—
Power:
Forwards	30			—			30			—
Futures	—			—			—			—
Options — Calls	3			3			—			—
Natural Gas Liquids – Forwards/Swaps	76			76			—			—
Refined Products — Futures	10			10			—			—
Crude – Futures	5			5			—			—
Total commodity derivatives	193			153			40			—
Total assets	$	222		$	153		$	69		$	—
Liabilities:
Interest rate derivatives	$	(358	)	$	—		$	(358	)	$	—
Embedded derivatives in the ETP Preferred Units	(9		)	—			—			(9		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(17		)	(17		)	—			—
Swing Swaps IFERC	(6		)	(1		)	(5		)	—
Fixed Swaps/Futures	(64		)	(64		)	—			—
Forward Physical Swaps	(2		)	—			(2		)	—
Power:
Forwards	(28		)	—			(28		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids – Forwards/Swaps	(88		)	(88		)	—			—
Refined Products — Futures	(21		)	(21		)	—			—
Crude — Futures	(7		)	(7		)	—			—
Total commodity derivatives	(234		)	(199		)	(35		)	—
Total liabilities	$	(601	)	$	(199	)	$	(393	)	$	(9	)

	Fair Value Measurements at December 31, 2015
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—			—
Swing Swaps IFERC	10			2			8			—
Fixed Swaps/Futures	274			274			—			—
Forward Physical Contracts	4			—			4			—
Power:
Forwards	22			—			22			—
Futures	3			3			—			—
Options — Calls	1			1			—			—
Options — Puts	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	99			99			—			—
Refined Products — Futures	15			15			—			—
Crude - Futures	9			9			—			—
Total commodity derivatives	454			420			34			—
Total assets	$	454		$	420		$	34		$	—
Liabilities:
Interest rate derivatives	$	(171	)	$	—		$	(171	)	$	—
Embedded derivatives in the ETP Preferred Units	(5		)	—			—			(5		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(16		)	(16		)	—			—
Swing Swaps IFERC	(12		)	(2		)	(10		)	—
Fixed Swaps/Futures	(203		)	(203		)	—			—
Power:
Forwards	(22		)	—			(22		)	—
Futures	(2		)	(2		)	—			—
Options — Calls	(1		)	(1		)	—			—
Natural Gas Liquids — Forwards/Swaps	(89		)	(89		)	—			—
Refined Products — Futures	(6		)	(6		)	—			—
Crude - Futures	(5		)	(5		)	—			—
Total commodity derivatives	(356		)	(324		)	(32		)	—
Total liabilities	$	(532	)	$	(324	)	$	(203	)	$	(5	)

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the six months endedJune 30, 2016.

Balance, December 31, 2015	$	(5	)
Net unrealized gains included in other income (expense)	(4		)
Balance, June 30, 2016	$	(9	)

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Net Income per Limited Partner Unit

6 Months Ended

Jun. 30, 2016

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net Income	$	424	$	772	$	760	$	993
Less: Income attributable to noncontrolling interest	183		474		207		411
Net Income, net of noncontrolling interest	241		298		553		582
Less: General Partner’s interest in income	1		—		2		1
Less: Convertible Unitholders’ interest in income	1		—		1		—
Less: Class D Unitholder’s interest in income	—		—		—		1
Income available to Limited Partners	$	239	$	298	$	550	$	580
Basic Income per Limited Partner Unit:
Weighted average limited partner units	1,048.9		1,076.0		1,046.9		1,077.2
Basic income per Limited Partner unit	$	0.23	$	0.28	$	0.53	$	0.54
Diluted Income per Limited Partner Unit:
Income available to Limited Partners	$	239	$	298	$	550	$	580
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and distributions to Convertible Unitholders	1		1		1		1
Diluted income available to Limited Partners	$	240	$	299	$	551	$	581
Weighted average limited partner units	1,048.9		1,076.0		1,046.9		1,077.2
Dilutive effect of unconverted unit awards and Convertible Units	14.9		1.6		5.6		1.8
Diluted weighted average limited partner units	1,063.8		1,077.6		1,052.5		1,079.0
Diluted income per Limited Partner unit	$	0.23	$	0.28	$	0.52	$	0.54

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Debt Obligations

6 Months Ended

Jun. 30, 2016

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.

Revolving Credit Facility

The Parent Company’s revolving credit facility has a capacity of $1.5 billion. As of June 30, 2016, there were $885 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $615 million.

Subsidiary Indebtedness

ETP Senior Notes

Subsequent to the Regency Merger in 2015, ETP assumed $3.80 billion total aggregate principal amount of Regency’s senior notes, which remained outstanding as of June 30, 2016. These notes were previously guaranteed by certain consolidated subsidiaries that had previously been consolidated by Regency. The subsidiary guarantees on all of these outstanding notes have been released.

Sunoco Logistics Senior Notes

Sunoco Logistics had$175 millionof6.125%senior notes which matured and were repaid in May 2016, using borrowings under the$2.50 billionSunoco Logistics Credit Facility.

In July 2016, Sunoco Logistics issued$550 millionaggregate principal amount of3.90%senior notes due in July 2026. The net proceeds from this offering were used to repay outstanding credit facility borrowings and for general partnership purposes.

Sunoco LP Term Loan and Senior Notes

In March 2016, Sunoco LP entered into a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. As of June 30, 2016, Sunoco LP had $1.2 billion outstanding under the term loan. Amounts borrowed under the term loan bear interest at either LIBOR or base rate plus an applicable margin based on Sunoco LP’s election for each interest period. The proceeds were used to fund a portion of the ETP dropdown and to pay fees and expenses incurred in connection with the ETP dropdown and the term loan.

In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 2019. The indebtedness under the ETP Credit Facility is unsecured, is not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. As of June 30, 2016, the ETP Credit Facility had $1.13 billion of outstanding borrowings.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of June 30, 2016, the Sunoco Logistics Credit Facility had $1.26 billion of outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.5 billion revolving credit facility (the “Sunoco LP Credit Facility”), which expires in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. As of June 30, 2016, the Sunoco LP Credit Facility had $675 million of outstanding borrowings and $22 million in standby letters of credit.

Bakken Financing

In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”). The $2.50 billion facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects.

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 June 30, 2016.

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Equity

6 Months Ended

Jun. 30, 2016

Partners' Capital Notes [Abstract]

Equity

EQUITY

ETE

The changes in ETE common units and Convertible Units during the six months ended June 30,2016 were as follows:

	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2015	—	1,044.8
Issuance of Series A Convertible Preferred Units	329.3	—
Outstanding at June 30, 2016	329.3	1,044.8

Series A Convertible Preferred Units

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.

The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $59 million carrying value as of June 30, 2016.

ETE issued 329,299,267 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.

Repurchase Program

During the six months endedJune 30, 2016, ETE did not repurchase any ETE common units under its current buyback program. As of June 30, 2016, $936 million remained available to repurchase under the current program.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the six months ended June 30, 2016, we recognized decreases in partners’ capital of $12 million.

ETP Common Unit Transactions

During thesix months ended June 30,2016, ETP received proceeds of $324 million, net of $3 million commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of June 30, 2016, approximately none of ETP’s common units were available to be issued under an equity distribution agreement. In July 2016, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.50 billion.

During the six months ended June 30,2016, distributions of $84 million were reinvested under ETP’s distribution reinvestment plan resulting in the issuance of 3.1 million common units. As of June 30, 2016, a total of 8.4 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment plan.

Sunoco Logistics Common Unit Transactions

During the six months endedJune 30, 2016, Sunoco Logistics received proceeds of $667 million, net of commissions of $7 million, from the issuance of Sunoco Logistics common units pursuant to equity distribution agreements, which were used for general partnership purposes.

Sunoco LP Common Unit Transactions

In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.

In March 2016, ETP contributed to Sunoco LP its remaining68.42%interest in Sunoco, LLC and100%interest in the legacy Sunoco, Inc. retail business for$2.23 billion. Sunoco LP paid$2.20 billionin cash, including a working capital adjustment, and issued5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.

On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.

Bakken Equity Sale

In August 2016, ETP and Sunoco Logistics announced they have signed an agreement to sell 36.75% of the Bakken Pipeline project to MarEn Bakken Company LLC, an entity jointly owned by Enbridge Energy Partners, L.P. and Marathon Petroleum Corporation, for $2.00 billion in cash. The sale is expected to close in the third quarter of 2016, subject to certain closing conditions. ETP and Sunoco Logistics will receive $1.20 billion and $800 million in cash at closing, respectively, and will own a combined 38.25% of the Bakken Pipeline project.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 4, 2016	February 19, 2016	$	0.2850
March 31, 2016	May 6, 2016	May 19, 2016	0.2850
June 30, 2016	August 8, 2016	August 19, 2016	0.2850

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 16, 2016	$	1.0550
March 31, 2016	May 6, 2016	May 16, 2016	1.0550
June 30, 2016	August 8, 2016	August 15, 2016	1.0550

In July 2016, ETE agreed to relinquish incentive distributions over seven quarters, beginning with $75 millionfor the quarter ended June 30, 2016. ETE has also previously agreed to relinquish additional incentive distributions. In the aggregate, including relinquishment agreed to in July 2016, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units.

	Total Year
2016 (remainder)	$	249
2017	593
2018	105
2019	95

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 12, 2016	$	0.4790
March 31, 2016	May 9, 2016	May 13, 2016	0.4890
June 30, 2016	August 8, 2016	August 12, 2016	0.5000

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 5, 2016	February 16, 2016	$	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255

Accumulated Other Comprehensive Income

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

	June 30, 2016			December 31, 2015
Available-for-sale securities	$	5		$	—
Foreign currency translation adjustment	(5		)	(4		)
Actuarial loss related to pensions and other postretirement benefits	5			8
Investments in unconsolidated affiliates, net	(11		)	—
Subtotal	(6		)	4
Amounts attributable to noncontrolling interest	6			(4		)
Total AOCI, net of tax	$	—		$	—

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Income Taxes (Notes)

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

For the three and six months endedJune 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries. Also, for the three months ended June 30, 2015, the Partnership income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

6 Months Ended

Jun. 30, 2016

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchasers. In June 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement.  As of June 30, 2016, ETP continued to provide contingent, residual support of approximately $1 billion of borrowings.

ETP Retail Holdings Guarantee of Sunoco LP Notes

Retail Holdings has provided a guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion of borrowings outstanding under Sunoco LP’s Term Loan.

NGL Pipeline Regulation

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

FERC Audit

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

Commitments

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Rental expense(1)	$	57		$	54		$	108		$	106
Less: Sublease rental income	(5		)	(4		)	(12		)	(12		)
Rental expense, net	$	52		$	50		$	96		$	94

⁽¹⁾  Includes contingent rentals totaling $7 million and $6 million for the three months ended June 30,2016 and 2015, respectively, and $9 million and $10 million for the six months ended June 30,2016 and 2015, respectively.

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

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business.  Natural gas and crude oil are flammable and combustible.  Serious personal injury and significant property damage can arise in connection with their transportation, storage or use.  In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage.  We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry.  However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

Mont Belvieu Incident

On June 26, 2016, a subsurface release of hydrocarbons and water, and a subsequent fire, occurred at Lone Star’s South Terminal.  All employees and contractors were accounted for, and there were no injuries. The cause of the fire and evaluation of possible damages is currently under investigation.

MTBE Litigation

Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater.  The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities.  The plaintiffs primarily assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices.  The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As ofJune 30, 2016, Sunoco, Inc. is a defendant infivecases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action.Fourof these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.

Fact discovery has concluded with respect to an initial set of19sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. The initial set of19 New Jersey trial sites are now pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. Sunoco informed Judge Goodman it is open to participating in global settlement discussions in a global mediation forum. The remaining portion of the New Jersey case remains in the MDL. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency Merger, purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware. The lawsuit alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ Answering Brief is currently due on July 29, 2016.

Jamie Welch Litigation

On March 10, 2016, Jamie Welch (“Welch”) filed an original petition against ETE and LE GP, LLC (“LE GP”) in Texas state court in Dallas. Welch alleges that Defendants 1) breached their contractual obligation to deliver and convert Welch’s Class D units upon termination; 2) failed to deliver long term incentive shares awarded to Welch; 3) failed to pay Welch’s 2015 bonus; 4) breached their obligation to grant Welch an interest in the Lake Charles LNG project; and 5) breached their obligation to pay Welch his severance. Welch brings claims for breach of contract and quantum meruit. On April 12, 2016, Defendants removed Welch’s lawsuit from state court to federal court in Dallas pursuant to 28 U.S.C. §§ 1441 and 1446. On April 29, 2016, Welch filed an amended complaint and removed his claim for payment of severance benefits.

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

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

Litigation Filed By or Against WMB

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

During a hearing on April 14, 2016, the Court granted WMB’s request to expedite the case and set a permanent injunction hearing for June 15, 2016.

On the same day that it filed the First Delaware WMB Litigation, WMB also filed a petition against Mr. Warren individually in the District Court of Dallas County, Texas (the “Texas WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Kelcy L. Warren, C.A. No. DC-16-03941. Mr. Warren sought dismissal of this lawsuit on the ground that WMB violated the Merger Agreement’s mandatory forum selection clause by filing the Texas WMB Litigation in Texas and not Delaware. On May 25, 2016, the Dallas court granted Mr. Warren’s motion and dismissed the Texas WMB Litigation without prejudice.

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

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

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

After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’s requests for injunctive relief. WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., No. 330, 2016. WMB’s initial appellate brief is due on August 11, 2016.

ETE intends to pursue its counterclaims, including its claim that WMB modified or qualified its board recommendation, which would entitle ETE to a termination fee of $1.48 billion if ETE were successful in proving that claim. ETE also intends to seek damages for WMB’s other breaches of the Merger Agreement.

Litigation Relating to the WMB Merger

Between October 5, 2015, and December 24, 2015, purported WMB stockholders filed six putative class action lawsuits in the Delaware Court of Chancery challenging the merger. The suits are captioned Greenwald et al. v. The Williams Companies, Inc., et al., C.A. No. 11573-VCG; Ozaki v. Armstrong et al., C.A. No. 11574-VCG; Blystone v. The Williams Companies, Inc., et al., C.A. No. 11601-VCG; Glener et al. v. The Williams Companies, Inc., et al., C.A. No. 11606-VCG; Amaitis et al. v. Armstrong et al., C.A. No. 11809-VCG; and State-Boston Retirement System et al. v. Armstrong et al., C.A. No. 11844-VCG. The complaints assert various claims against the individual members of WMB’s board of directors; ETE, ETC, ETC GP, LE GP and ETE GP (the “ETE Defendants”); WMB; and others. On January 13, 2016, the Court consolidated these six actions into a new consolidated action captioned In re The Williams Companies, Inc. Merger Litigation, Consolidated C.A. No. 11844-VCG (the “Merger Litigation”). In its stipulated order, the Court dismissed without prejudice the ETE Defendants (among others) from the consolidated action.

On January 14, 2016, a purported WMB stockholder (“Bumgarner”) filed a putative class action lawsuit against WMB and ETE, captioned Bumgarner v. The Williams Companies, Inc., et al., Case No. 16-cv-26-GKF-FHM, in the United States District Court for the Northern District of Oklahoma. Bumgarner alleged that ETE and WMB violated Section 14 of the Securities Exchange Act of 1934 (the “Exchange Act”) by making allegedly false statements concerning the merger. As relief, the complaint sought an injunction against the proposed merger. On February 1, 2016, Bumgarner filed an amended complaint, making substantially the same allegations. On February 19, 2016, ETE and WMB moved to dismiss the amended complaint. Bumgarner moved for expedited discovery on April 21, 2016. On April 28, 2016, the Court granted the motion to dismiss and dismissed Bumgarner’s claims in their entirety with leave to amend. The Court also granted expedited proceedings. Bumgarner amended his complaint on May 12, 2016, and ETE and WMB again moved to dismiss. The Court granted the motion in part and denied it in part on May 26, 2016, and Bumgarner amended his complaint the same day. Following a motion to reconsider filed by ETE and WMB, the Court revised its Order on the motion to dismiss on June 3, 2016. Bumgarner filed a second motion for a preliminary injunction on June 10, 2016. On June 16, 2016, the parties reached a settlement agreement, and Bumgarner withdrew his motion for a preliminary injunction. Pursuant to the agreement, WMB issued a press release and agreed to provide an updated disclosure to its proxy statement in connection with the merger. WMB also agreed to pay Bumgarner’s attorney fees. On July 28, 2016, Bumgarner’s claim was dismissed with prejudice.

On January 19, 2016, The City of Birmingham Retirement and Relief System (“CBRRS”), a purported shareholder of WMB, filed a putative class action lawsuit against the members of WMB’s board of directors, WMB, ETE, ETC, ETC GP, LE GP, and ETE GP challenging the merger and the disclosures made in connection with the merger. The lawsuit was styled City of Birmingham Retirement and Relief System v. Alan S. Armstrong, et al., C.A. No. 16-17-RGA, in the United States District Court for the District of Delaware. CBRRS alleged violations of Section 14(a) and 20(a) of the Exchange Act among other claims. CBRRS moved to expedite, and Defendants moved to dismiss the suit. The Court denied expedition. CBRRS voluntarily dismissed the suit on March 7, 2016.

Unitholder Litigation Relating to the Issuance

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against, Energy Transfer Equity, L.P. and LE GP, LLC, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware. One of the Issuance Plaintiffs had initially filed an action to inspect the books and records of ETE on April 11, 2016 but voluntarily dismissed the books and records action on April 22, 2016.

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

One of the Issuance Plaintiffs moved for expedited proceedings. The Delaware Court of Chancery granted a Motion to Expedite filed by one of the Issuance Plaintiffs and stated that the injunction hearing should be held before any August 2016 distribution. Defendants intend to vigorously defend this consolidated lawsuit.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of June 30, 2016 and December 31, 2015, accruals of approximately $59 million and $40 million, respectively, were reflected on our balance sheets related to these contingent obligations.  As new information becomes available, our estimates may change.  The impact of these changes may have a significant effect on our results of operations in a single period.

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

No amounts have been recorded in our June 30, 2016 or December 31, 2015 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Attorney General of the Commonwealth of Massachusetts v. New England Gas Company.

On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Compliance Orders from the New Mexico Environmental Department

Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

Lone Star NGL Fractionators Notice of Enforcement

Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to its Mont Belvieu Gas Plant. The Partnership has accrued $300,000 related to the claim. As of April 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 penalty and a $21,000 Supplemental Environmental Project.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites.  Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products.  As a result, there can be no assurance that significant costs and liabilities will not be incurred.  Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits.  Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

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

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

Environmental Remediation

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

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

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

• Currently operating Sunoco, Inc. retail sites.

• Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include 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 identifiedas a potentially responsible party (“PRP”).  As of June 30, 2016, Sunoco, Inc. had been named as a PRP at approximately 49 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law.  Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site.  Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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

	June 30, 2016		December 31, 2015
Current	$	42	$	42
Non-current	323		326
Total environmental liabilities	$	365	$	368

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

During the three months ended June 30,2016 and 2015, Sunoco, Inc. and Sunoco LP collectively recorded $11 million and $11 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30,2016 and 2015, Sunoco, Inc. and Sunoco LP recorded $19 million and $18 million, respectively, of expenditures related to environmental cleanup programs.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period.  On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued an 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 that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.  Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.”  Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis.  Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

In January 2012, Sunoco Logistics experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco Logistics is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco Logistics also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco Logistics has also received a "No Further Action" approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, Sunoco Logistics received a proposed penalty from the EPA and U.S. Department of Justice associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.

Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees.  In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.  We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

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Derivative Assets And Liabilities

6 Months Ended

Jun. 30, 2016

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Derivative Assets And Liabilities

DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

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

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

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

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

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

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

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing segment. These contracts are not designated as hedges for accounting purposes.

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

The following table details our outstanding commodity-related derivatives:

	June 30, 2016			December 31, 2015
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	5,825,000		2016-2017	(602,500	)	2016-2017
Basis Swaps IFERC/NYMEX (1)	7,920,000		2016-2017	(31,240,000	)	2016-2017
Power (Megawatt):
Forwards	272,164		2016-2017	357,092		2016-2017
Futures	(320,257	)	2016-2017	(109,791	)	2016
Options — Puts	(424,000	)	2016	260,534		2016
Options — Calls	696,000		2016	1,300,647		2016
Crude (Bbls):
Futures	(222,000	)	2016-2017	(591,000	)	2016-2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(522,500	)	2016-2017	(6,522,500	)	2016-2017
Swing Swaps IFERC	34,465,000		2016-2017	71,340,000		2016-2017
Fixed Swaps/Futures	(3,835,000	)	2016-2018	(14,380,000	)	2016-2018
Forward Physical Contracts	3,838,458		2016-2017	21,922,484		2016-2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(10,443,400	)	2016	(8,146,800	)	2016-2018
Refined Products (Bbls) — Futures	(1,784,000	)	2016-2017	(1,289,000	)	2016-2017
Corn (Bushels) — Futures	(1,635,000	)	2016	1,185,000		2016
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(42,167,500	)	2016-2017	(37,555,000	)	2016
Fixed Swaps/Futures	(42,167,500	)	2016-2017	(37,555,000	)	2016
Hedged Item — Inventory	42,167,500		2016-2017	37,555,000		2016

⁽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 floating rate debt. We also manage our interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and floating 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)	June 30, 2016		December 31, 2015
July 2016(2)(4)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	200
July 2017(3)(4)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	500		300
July 2018(3)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300
July 2019(3)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200

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

⁽²⁾  Represents the effective date. These forward-starting swaps have a term of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million.  In June 2016, ETP extended the expiration of those swaps to July 2017. 

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
	June 30, 2016		December 31, 2015		June 30, 2016			December 31, 2015
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	38	$	(4	)	$	(3	)
	—		38		(4		)	(3		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	138	$	353	$	(173	)	$	(306	)
Commodity derivatives	55		63		(57		)	(47		)
Interest rate derivatives	29		—		(9		)	(171		)
Embedded derivatives in the ETP Preferred Units	—		—		(358		)	(5		)
	222		416		(597		)	(529		)
Total derivatives	$	222	$	454	$	(601	)	$	(532	)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	June 30, 2016			December 31, 2015			June 30, 2016			December 31, 2015
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	29		$	—		$	(367	)	$	(176	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	55			63			(57		)	(47		)
Broker cleared derivative contracts	Other current assets	138			391			(177		)	(309		)
Total gross derivatives		222			454			(601		)	(532		)
Less offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(28		)	(17		)	28			17
Payments on margin deposit	Other current assets	(138		)	(309		)	138			309
Total net derivatives		$	56		$	128		$	(435	)	$	(206	)

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:

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	—	$	—	$	—	$	1
Total	$	—	$	—	$	—	$	1

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2016		2015		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	21	$	11	$	17	$	8
Total		$	21	$	11	$	17	$	8

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2016			2015			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading	Cost of products sold	$	(7	)	$	(6	)	$	(16	)	$	(8	)
Commodity derivatives —Non-trading	Cost of products sold	(53		)	(40		)	(45		)	(48		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(81		)	127			(151		)	50
Embedded derivatives	Other, net	(4		)	2			(4		)	4
Total		$	(145	)	$	83		$	(216	)	$	(2	)

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Related Party Transactions

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

The Parent Company has agreements with subsidiaries to provide or receive various management and general and administrative services. The Parent Company pays ETP to provide services on its behalf and on behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

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

In addition, ETE recorded sales with affiliates of $45 million and $130 million during the three months endedJune 30, 2016 and 2015, respectively, and $126 million and $206 million during the six months endedJune 30, 2016 and 2015, respectively.

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Reportable Segments

6 Months Ended

Jun. 30, 2016

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. ETE’s consolidated results reflect the elimination of Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.

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

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

The following tables present financial information by segment:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Segment Adjusted EBITDA:
Investment in ETP	$	1,370		$	1,488		$	2,782		$	2,854
Investment in Sunoco LP	164			142			323			271
Investment in Lake Charles LNG	44			49			88			98
Corporate and Other	(68		)	(25		)	(105		)	(48		)
Adjustments and Eliminations	(125		)	(142		)	(125		)	(271		)
Total	1,385			1,512			2,963			2,904
Depreciation, depletion and amortization	(588		)	(514		)	(1,150		)	(1,007		)
Interest expense, net	(450		)	(408		)	(877		)	(779		)
Gains (losses) on interest rate derivatives	(81		)	127			(151		)	50
Non-cash unit-based compensation expense	(22		)	(25		)	(23		)	(48		)
Unrealized losses on commodity risk management activities	(24		)	(44		)	(84		)	(119		)
Losses on extinguishments of debt	—			(33		)	—			(33		)
Inventory valuation adjustments	181			184			168			150
Equity in earnings of unconsolidated affiliates	95			117			156			174
Adjusted EBITDA related to unconsolidated affiliates	(127		)	(215		)	(346		)	(361		)
Other, net	46			15			40			18
Income before income tax benefit	$	415		$	716		$	696		$	949

	June 30, 2016			December 31, 2015
Assets:
Investment in ETP	$	66,041		$	65,173
Investment in Sunoco LP	8,762			8,842
Investment in Lake Charles LNG	1,437			1,369
Corporate and Other	656			638
Adjustments and Eliminations	(2,336		)	(4,833		)
Total assets	$	74,560		$	71,189

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues:
Investment in ETP:
Revenues from external customers	$	5,245		$	11,540		$	9,679		$	21,866
Intersegment revenues	44			—			91			—
	5,289			11,540			9,770			21,866
Investment in Sunoco LP:
Revenues from external customers	4,050			5,126			7,249			9,477
Intersegment revenues	2			—			5			—
	4,052			5,126			7,254			9,477
Investment in Lake Charles LNG:
Revenues from external customers	49			54			98			108
Adjustments and Eliminations	(46		)	(5,126		)	(96		)	(9,477		)
Total revenues	$	9,344		$	11,594		$	17,026		$	21,974

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Intrastate Transportation and Storage	$	428	$	486	$	874	$	1,027
Interstate Transportation and Storage	229		239		483		510
Midstream	690		767		1,217		1,516
Liquids Transportation and Services	1,099		783		1,928		1,595
Investment in Sunoco Logistics	2,250		3,120		3,979		5,646
Retail Marketing	—		5,557		—		10,339
All Other	593		588		1,289		1,233
Total revenues	5,289		11,540		9,770		21,866
Less: Intersegment revenues	44		—		91		—
Revenues from external customers	$	5,245	$	11,540	$	9,679	$	21,866

Investment in Sunoco LP

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Retail operations	$	2,019	$	2,259	$	3,693	$	4,155
Wholesale operations	2,033		2,867		3,561		5,322
Total revenues	4,052		5,126		7,254		9,477
Less: Intersegment revenues	2		—		5		—
Revenues from external customers	$	4,050	$	5,126	$	7,249	$	9,477

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

6 Months Ended

Jun. 30, 2016

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)

	June 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	1
Accounts receivable from related companies	41			34
Other current assets	1			—
Total current assets	43			35
Property, plant and equipment, net	35			20
Advances to and investments in unconsolidated affiliates	5,074			5,764
Intangible assets, net	3			6
Goodwill	9			9
Other non-current assets, net	10			10
Total assets	$	5,174		$	5,844
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	1		$	—
Accounts payable to related companies	58			111
Interest payable	66			66
Accrued and other current liabilities	13			1
Total current liabilities	138			178
Long-term debt, less current maturities	6,362			6,332
Note payable to related company	353			265
Other non-current liabilities	2			1
Commitments and contingencies
Partners’ capital:
General Partner	(2		)	(2		)
Limited Partners:
Common Unitholders	(1,738		)	(952		)
Class D Units	—			22
Series A Convertible Preferred Units	59			—
Total partners’ capital (deficit)	(1,681		)	(932		)
Total liabilities and partners’ capital	$	5,174		$	5,844

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(44	)	$	(29	)	$	(81	)	$	(57	)
OTHER INCOME (EXPENSE):
Interest expense, net	(82		)	(72		)	(163		)	(133		)
Equity in earnings of unconsolidated affiliates	369			398			799			771
Other, net	(2		)	—			(2		)	1
INCOME BEFORE INCOME TAXES	241			297			553			582
Income tax benefit	—			(1		)	—			—
NET INCOME	241			298			553			582
General Partner’s interest in net income	1			—			2			1
Convertible Unitholders’ interest in income	1			—			1			—
Class D Unitholder’s interest in net income	—			—			—			1
Limited Partners’ interest in net income	$	239		$	298		$	550		$	580

⁽¹⁾  Includes management fees paid by ETE to ETP.

STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
	2016			2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	507		$	475
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	—			(817		)
Contributions to unconsolidated affiliate	(65		)	—
Capital expenditures	(15		)	(7		)
Net cash used in investing activities	(80		)	(824		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	145			2,972
Principal payments on debt	(120		)	(1,915		)
Proceeds from affiliate	88			106
Distributions to partners	(540		)	(509		)
Units repurchased under buyback program	—			(294		)
Debt issuance costs	—			(12		)
Net cash provided by (used in) financing activities	(427		)	348
DECREASE IN CASH AND CASH EQUIVALENTS	—			(1		)
CASH AND CASH EQUIVALENTS, beginning of period	1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	1

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Operations And Organization Accounting policy (Policies)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

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

Subsidiary Common Unit Transactions

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

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

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

New Accounting Pronouncements, Policy [Policy Text Block]

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. The Partnership adopted this standard on January 1, 2016, and the adoption did not impact the Partnership’s financial position or results of operations.

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, if any, that adopting this new standard will have on the consolidated financial statements and related disclosures.

In March 2016, the FASB issued 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. In addition, the amendments in this update eliminate the guidance in Topic 718 that was indefinitely deferred shortly after the issuance of FASB Statement No. 123 (revised 2004), Share-Based Payment. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.

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Cash And Cash Equivalents (Tables)

6 Months Ended

Jun. 30, 2016

Supplemental Cash Flow Information [Abstract]

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

Non-cash investing activities were as follows:

	Six Months Ended June 30,
	2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	881		$	693
Gains (losses) from subsidiary common unit issuances, net	(12		)	50

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Inventories (Tables)

6 Months Ended

Jun. 30, 2016

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:

	June 30, 2016		December 31, 2015
Natural gas and NGLs	$	552	$	415
Crude oil	564		424
Refined products	452		420
Other	361		377
Total inventories	$	1,929	$	1,636

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Measurements [Abstract]

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2016 and December 31, 2015 based on inputs used to derive their fair values:

	Fair Value Measurements at June 30, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	29		$	—		$	29		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	18			18			—			—
Swing Swaps IFERC	6			—			6			—
Fixed Swaps/Futures	41			41			—			—
Forward Physical Swaps	4			—			4			—
Power:
Forwards	30			—			30			—
Futures	—			—			—			—
Options — Calls	3			3			—			—
Natural Gas Liquids – Forwards/Swaps	76			76			—			—
Refined Products — Futures	10			10			—			—
Crude – Futures	5			5			—			—
Total commodity derivatives	193			153			40			—
Total assets	$	222		$	153		$	69		$	—
Liabilities:
Interest rate derivatives	$	(358	)	$	—		$	(358	)	$	—
Embedded derivatives in the ETP Preferred Units	(9		)	—			—			(9		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(17		)	(17		)	—			—
Swing Swaps IFERC	(6		)	(1		)	(5		)	—
Fixed Swaps/Futures	(64		)	(64		)	—			—
Forward Physical Swaps	(2		)	—			(2		)	—
Power:
Forwards	(28		)	—			(28		)	—
Futures	(1		)	(1		)	—			—
Natural Gas Liquids – Forwards/Swaps	(88		)	(88		)	—			—
Refined Products — Futures	(21		)	(21		)	—			—
Crude — Futures	(7		)	(7		)	—			—
Total commodity derivatives	(234		)	(199		)	(35		)	—
Total liabilities	$	(601	)	$	(199	)	$	(393	)	$	(9	)

	Fair Value Measurements at December 31, 2015
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—			—
Swing Swaps IFERC	10			2			8			—
Fixed Swaps/Futures	274			274			—			—
Forward Physical Contracts	4			—			4			—
Power:
Forwards	22			—			22			—
Futures	3			3			—			—
Options — Calls	1			1			—			—
Options — Puts	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	99			99			—			—
Refined Products — Futures	15			15			—			—
Crude - Futures	9			9			—			—
Total commodity derivatives	454			420			34			—
Total assets	$	454		$	420		$	34		$	—
Liabilities:
Interest rate derivatives	$	(171	)	$	—		$	(171	)	$	—
Embedded derivatives in the ETP Preferred Units	(5		)	—			—			(5		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(16		)	(16		)	—			—
Swing Swaps IFERC	(12		)	(2		)	(10		)	—
Fixed Swaps/Futures	(203		)	(203		)	—			—
Power:
Forwards	(22		)	—			(22		)	—
Futures	(2		)	(2		)	—			—
Options — Calls	(1		)	(1		)	—			—
Natural Gas Liquids — Forwards/Swaps	(89		)	(89		)	—			—
Refined Products — Futures	(6		)	(6		)	—			—
Crude - Futures	(5		)	(5		)	—			—
Total commodity derivatives	(356		)	(324		)	(32		)	—
Total liabilities	$	(532	)	$	(324	)	$	(203	)	$	(5	)

Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the six months endedJune 30, 2016.

Balance, December 31, 2015	$	(5	)
Net unrealized gains included in other income (expense)	(4		)
Balance, June 30, 2016	$	(9	)

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Net Income per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 2016

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net Income	$	424	$	772	$	760	$	993
Less: Income attributable to noncontrolling interest	183		474		207		411
Net Income, net of noncontrolling interest	241		298		553		582
Less: General Partner’s interest in income	1		—		2		1
Less: Convertible Unitholders’ interest in income	1		—		1		—
Less: Class D Unitholder’s interest in income	—		—		—		1
Income available to Limited Partners	$	239	$	298	$	550	$	580
Basic Income per Limited Partner Unit:
Weighted average limited partner units	1,048.9		1,076.0		1,046.9		1,077.2
Basic income per Limited Partner unit	$	0.23	$	0.28	$	0.53	$	0.54
Diluted Income per Limited Partner Unit:
Income available to Limited Partners	$	239	$	298	$	550	$	580
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and distributions to Convertible Unitholders	1		1		1		1
Diluted income available to Limited Partners	$	240	$	299	$	551	$	581
Weighted average limited partner units	1,048.9		1,076.0		1,046.9		1,077.2
Dilutive effect of unconverted unit awards and Convertible Units	14.9		1.6		5.6		1.8
Diluted weighted average limited partner units	1,063.8		1,077.6		1,052.5		1,079.0
Diluted income per Limited Partner unit	$	0.23	$	0.28	$	0.52	$	0.54

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Equity (Tables)

6 Months Ended

Jun. 30, 2016

Schedule of Net IDR Subsidies [Table Text Block]

	Total Year
2016 (remainder)	$	249
2017	593
2018	105
2019	95

Change In ETE Common Units

The changes in ETE common units and Convertible Units during the six months ended June 30,2016 were as follows:

	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2015	—	1,044.8
Issuance of Series A Convertible Preferred Units	329.3	—
Outstanding at June 30, 2016	329.3	1,044.8

Accumulated Other Comprehensive Income

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

	June 30, 2016			December 31, 2015
Available-for-sale securities	$	5		$	—
Foreign currency translation adjustment	(5		)	(4		)
Actuarial loss related to pensions and other postretirement benefits	5			8
Investments in unconsolidated affiliates, net	(11		)	—
Subtotal	(6		)	4
Amounts attributable to noncontrolling interest	6			(4		)
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, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 4, 2016	February 19, 2016	$	0.2850
March 31, 2016	May 6, 2016	May 19, 2016	0.2850
June 30, 2016	August 8, 2016	August 19, 2016	0.2850

ETP [Member]

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

Following are distributions declared and/or paid by ETP subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 16, 2016	$	1.0550
March 31, 2016	May 6, 2016	May 16, 2016	1.0550
June 30, 2016	August 8, 2016	August 15, 2016	1.0550

Sunoco Logistics [Member]

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

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 12, 2016	$	0.4790
March 31, 2016	May 9, 2016	May 13, 2016	0.4890
June 30, 2016	August 8, 2016	August 12, 2016	0.5000

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, 2015:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 5, 2016	February 16, 2016	$	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255

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

6 Months Ended

Jun. 30, 2016

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 2058.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Rental expense(1)	$	57		$	54		$	108		$	106
Less: Sublease rental income	(5		)	(4		)	(12		)	(12		)
Rental expense, net	$	52		$	50		$	96		$	94

⁽¹⁾  Includes contingent rentals totaling

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.

	June 30, 2016		December 31, 2015
Current	$	42	$	42
Non-current	323		326
Total environmental liabilities	$	365	$	368

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Derivative Assets And Liabilities (Tables)

6 Months Ended

Jun. 30, 2016

Outstanding Commodity-Related Derivatives

The following table details our outstanding commodity-related derivatives:

	June 30, 2016			December 31, 2015
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	5,825,000		2016-2017	(602,500	)	2016-2017
Basis Swaps IFERC/NYMEX (1)	7,920,000		2016-2017	(31,240,000	)	2016-2017
Power (Megawatt):
Forwards	272,164		2016-2017	357,092		2016-2017
Futures	(320,257	)	2016-2017	(109,791	)	2016
Options — Puts	(424,000	)	2016	260,534		2016
Options — Calls	696,000		2016	1,300,647		2016
Crude (Bbls):
Futures	(222,000	)	2016-2017	(591,000	)	2016-2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(522,500	)	2016-2017	(6,522,500	)	2016-2017
Swing Swaps IFERC	34,465,000		2016-2017	71,340,000		2016-2017
Fixed Swaps/Futures	(3,835,000	)	2016-2018	(14,380,000	)	2016-2018
Forward Physical Contracts	3,838,458		2016-2017	21,922,484		2016-2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(10,443,400	)	2016	(8,146,800	)	2016-2018
Refined Products (Bbls) — Futures	(1,784,000	)	2016-2017	(1,289,000	)	2016-2017
Corn (Bushels) — Futures	(1,635,000	)	2016	1,185,000		2016
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(42,167,500	)	2016-2017	(37,555,000	)	2016
Fixed Swaps/Futures	(42,167,500	)	2016-2017	(37,555,000	)	2016
Hedged Item — Inventory	42,167,500		2016-2017	37,555,000		2016

⁽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)	June 30, 2016		December 31, 2015
July 2016(2)(4)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	200
July 2017(3)(4)	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	500		300
July 2018(3)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300
July 2019(3)	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200

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

⁽²⁾  Represents the effective date. These forward-starting swaps have a term of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million.  In June 2016, ETP extended the expiration of those swaps to July 2017. 

Fair Value Of Derivative Instruments

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	June 30, 2016		December 31, 2015		June 30, 2016			December 31, 2015
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	38	$	(4	)	$	(3	)
	—		38		(4		)	(3		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	138	$	353	$	(173	)	$	(306	)
Commodity derivatives	55		63		(57		)	(47		)
Interest rate derivatives	29		—		(9		)	(171		)
Embedded derivatives in the ETP Preferred Units	—		—		(358		)	(5		)
	222		416		(597		)	(529		)
Total derivatives	$	222	$	454	$	(601	)	$	(532	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	June 30, 2016			December 31, 2015			June 30, 2016			December 31, 2015
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	29		$	—		$	(367	)	$	(176	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	55			63			(57		)	(47		)
Broker cleared derivative contracts	Other current assets	138			391			(177		)	(309		)
Total gross derivatives		222			454			(601		)	(532		)
Less offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(28		)	(17		)	28			17
Payments on margin deposit	Other current assets	(138		)	(309		)	138			309
Total net derivatives		$	56		$	128		$	(435	)	$	(206	)

Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	—	$	—	$	—	$	1
Total	$	—	$	—	$	—	$	1

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

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,				Six Months Ended June 30,
		2016		2015		2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	21	$	11	$	17	$	8
Total		$	21	$	11	$	17	$	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 June 30,						Six Months Ended June 30,
		2016			2015			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading	Cost of products sold	$	(7	)	$	(6	)	$	(16	)	$	(8	)
Commodity derivatives —Non-trading	Cost of products sold	(53		)	(40		)	(45		)	(48		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(81		)	127			(151		)	50
Embedded derivatives	Other, net	(4		)	2			(4		)	4
Total		$	(145	)	$	83		$	(216	)	$	(2	)

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Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2016

Operating Segments [Member]

Financial Information By Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Segment Adjusted EBITDA:
Investment in ETP	$	1,370		$	1,488		$	2,782		$	2,854
Investment in Sunoco LP	164			142			323			271
Investment in Lake Charles LNG	44			49			88			98
Corporate and Other	(68		)	(25		)	(105		)	(48		)
Adjustments and Eliminations	(125		)	(142		)	(125		)	(271		)
Total	1,385			1,512			2,963			2,904
Depreciation, depletion and amortization	(588		)	(514		)	(1,150		)	(1,007		)
Interest expense, net	(450		)	(408		)	(877		)	(779		)
Gains (losses) on interest rate derivatives	(81		)	127			(151		)	50
Non-cash unit-based compensation expense	(22		)	(25		)	(23		)	(48		)
Unrealized losses on commodity risk management activities	(24		)	(44		)	(84		)	(119		)
Losses on extinguishments of debt	—			(33		)	—			(33		)
Inventory valuation adjustments	181			184			168			150
Equity in earnings of unconsolidated affiliates	95			117			156			174
Adjusted EBITDA related to unconsolidated affiliates	(127		)	(215		)	(346		)	(361		)
Other, net	46			15			40			18
Income before income tax benefit	$	415		$	716		$	696		$	949

Assets Segments [Member]

Financial Information By Segment

	June 30, 2016			December 31, 2015
Assets:
Investment in ETP	$	66,041		$	65,173
Investment in Sunoco LP	8,762			8,842
Investment in Lake Charles LNG	1,437			1,369
Corporate and Other	656			638
Adjustments and Eliminations	(2,336		)	(4,833		)
Total assets	$	74,560		$	71,189

Sales Revenue, Segment [Member]

Financial Information By Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues:
Investment in ETP:
Revenues from external customers	$	5,245		$	11,540		$	9,679		$	21,866
Intersegment revenues	44			—			91			—
	5,289			11,540			9,770			21,866
Investment in Sunoco LP:
Revenues from external customers	4,050			5,126			7,249			9,477
Intersegment revenues	2			—			5			—
	4,052			5,126			7,254			9,477
Investment in Lake Charles LNG:
Revenues from external customers	49			54			98			108
Adjustments and Eliminations	(46		)	(5,126		)	(96		)	(9,477		)
Total revenues	$	9,344		$	11,594		$	17,026		$	21,974

Investment In ETP [Member]

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

Investment in ETP

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Intrastate Transportation and Storage	$	428	$	486	$	874	$	1,027
Interstate Transportation and Storage	229		239		483		510
Midstream	690		767		1,217		1,516
Liquids Transportation and Services	1,099		783		1,928		1,595
Investment in Sunoco Logistics	2,250		3,120		3,979		5,646
Retail Marketing	—		5,557		—		10,339
All Other	593		588		1,289		1,233
Total revenues	5,289		11,540		9,770		21,866
Less: Intersegment revenues	44		—		91		—
Revenues from external customers	$	5,245	$	11,540	$	9,679	$	21,866

Investment In Sunoco LP [Member]

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

Investment in Sunoco LP

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Retail operations	$	2,019	$	2,259	$	3,693	$	4,155
Wholesale operations	2,033		2,867		3,561		5,322
Total revenues	4,052		5,126		7,254		9,477
Less: Intersegment revenues	2		—		5		—
Revenues from external customers	$	4,050	$	5,126	$	7,249	$	9,477

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

6 Months Ended

Jun. 30, 2016

Schedule Of Balance Sheets

BALANCE SHEETS

(unaudited)

	June 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	1
Accounts receivable from related companies	41			34
Other current assets	1			—
Total current assets	43			35
Property, plant and equipment, net	35			20
Advances to and investments in unconsolidated affiliates	5,074			5,764
Intangible assets, net	3			6
Goodwill	9			9
Other non-current assets, net	10			10
Total assets	$	5,174		$	5,844
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	1		$	—
Accounts payable to related companies	58			111
Interest payable	66			66
Accrued and other current liabilities	13			1
Total current liabilities	138			178
Long-term debt, less current maturities	6,362			6,332
Note payable to related company	353			265
Other non-current liabilities	2			1
Commitments and contingencies
Partners’ capital:
General Partner	(2		)	(2		)
Limited Partners:
Common Unitholders	(1,738		)	(952		)
Class D Units	—			22
Series A Convertible Preferred Units	59			—
Total partners’ capital (deficit)	(1,681		)	(932		)
Total liabilities and partners’ capital	$	5,174		$	5,844

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	$	(44	)	$	(29	)	$	(81	)	$	(57	)
OTHER INCOME (EXPENSE):
Interest expense, net	(82		)	(72		)	(163		)	(133		)
Equity in earnings of unconsolidated affiliates	369			398			799			771
Other, net	(2		)	—			(2		)	1
INCOME BEFORE INCOME TAXES	241			297			553			582
Income tax benefit	—			(1		)	—			—
NET INCOME	241			298			553			582
General Partner’s interest in net income	1			—			2			1
Convertible Unitholders’ interest in income	1			—			1			—
Class D Unitholder’s interest in net income	—			—			—			1
Limited Partners’ interest in net income	$	239		$	298		$	550		$	580

⁽¹⁾  Includes management fees paid by ETE to ETP.

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
	2016			2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	507		$	475
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	—			(817		)
Contributions to unconsolidated affiliate	(65		)	—
Capital expenditures	(15		)	(7		)
Net cash used in investing activities	(80		)	(824		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	145			2,972
Principal payments on debt	(120		)	(1,915		)
Proceeds from affiliate	88			106
Distributions to partners	(540		)	(509		)
Units repurchased under buyback program	—			(294		)
Debt issuance costs	—			(12		)
Net cash provided by (used in) financing activities	(427		)	348
DECREASE IN CASH AND CASH EQUIVALENTS	—			(1		)
CASH AND CASH EQUIVALENTS, beginning of period	1			2
CASH AND CASH EQUIVALENTS, end of period	$	1		$	1

XML

Acquisitions Narrative (Details) - USD ($) shares in Millions, $ in Millions	1 Months Ended	6 Months Ended
	Mar. 31, 2016	Jun. 30, 2016
Sunoco, LLC [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	68.42%
Legacy Sunoco, Inc. [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
Sunoco LP [Member]
Business Combination, Consideration Transferred		$ 114
Goodwill, Period Increase (Decrease)		45
Sunoco LP [Member] | Dropdown of Sunoco LLC Interest [Member]
Business Combination, Consideration Transferred	$ 2,230
Payments to Acquire Businesses, Gross	$ 2,200
Sale of Stock, Number of Shares Issued in Transaction	5.7
Sunoco LP [Member] | Emerge Energy Services LP [Member]
Business Combination, Consideration Transferred		$ 179

XML

Cash And Cash Equivalents Non-Cash Activities (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 881	$ 693
Gains (losses) from subsidiary common unit issuances, net	$ (12)	$ 50

XML

Inventories Table - Inventory Balances (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Inventory, Net [Abstract]
Natural gas and NGLs	$ 552	$ 415
Crude oil	564	424
Refined products	452	420
Other	361	377
Total inventories	$ 1,929	$ 1,636

XML

Fair Value Measurements Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Fair Value Measurements [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0
Debt obligations, fair value	39,840	$ 33,220
Long-term Debt	$ 39,510	$ 36,970

XML

Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Liabilities, Fair Value Disclosure, Recurring	$ (601)	$ (532)
Level 1
Liabilities, Fair Value Disclosure, Recurring	(199)	(324)
Level 2
Liabilities, Fair Value Disclosure, Recurring	(393)	(203)
Level 3
Liabilities, Fair Value Disclosure, Recurring	(9)	(5)
Commodity Derivatives - Power [Member] | Call Option [Member]
Price Risk Derivative Assets, at Fair Value		1
Commodity Derivatives - Power [Member] | Options - Puts [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 1 | Options - Puts [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 2 | Options - Puts [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
Commodity Derivatives - Power [Member] | Level 3 | Options - Puts [Member]
Price Risk Derivative Assets, at Fair Value		0
Fair Value, Measurements, Recurring [Member]
Interest Rate Derivative Assets, at Fair Value	29
Price Risk Derivative Assets, at Fair Value	193	454
Assets, Fair Value Disclosure	222	454
Interest Rate Derivative Liabilities, at Fair Value	(358)	(171)
Embedded Derivative, Fair Value of Embedded Derivative Liability	(9)	(5)
Price Risk Derivative Liabilities, at Fair Value	(234)	(356)
Fair Value, Measurements, Recurring [Member] | Level 1
Interest Rate Derivative Assets, at Fair Value	0
Price Risk Derivative Assets, at Fair Value	153	420
Assets, Fair Value Disclosure	153	420
Interest Rate Derivative Liabilities, at Fair Value	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	0
Price Risk Derivative Liabilities, at Fair Value	(199)	(324)
Fair Value, Measurements, Recurring [Member] | Level 2
Interest Rate Derivative Assets, at Fair Value	29
Price Risk Derivative Assets, at Fair Value	40	34
Assets, Fair Value Disclosure	69	34
Interest Rate Derivative Liabilities, at Fair Value	(358)	(171)
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	0
Price Risk Derivative Liabilities, at Fair Value	(35)	(32)
Fair Value, Measurements, Recurring [Member] | Level 3
Interest Rate Derivative Assets, at Fair Value	0
Price Risk Derivative Assets, at Fair Value	0	0
Assets, Fair Value Disclosure	0	0
Interest Rate Derivative Liabilities, at Fair Value	0	0
Embedded Derivative, Fair Value of Embedded Derivative Liability	(9)	(5)
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	18	16
Price Risk Derivative Liabilities, at Fair Value	(17)	(16)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	6	10
Price Risk Derivative Liabilities, at Fair Value	(6)	(12)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	41	274
Price Risk Derivative Liabilities, at Fair Value	(64)	(203)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	4	4
Price Risk Derivative Liabilities, at Fair Value	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	18	16
Price Risk Derivative Liabilities, at Fair Value	(17)	(16)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	0	2
Price Risk Derivative Liabilities, at Fair Value	(1)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	41	274
Price Risk Derivative Liabilities, at Fair Value	(64)	(203)
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	6	8
Price Risk Derivative Liabilities, at Fair Value	(5)	(10)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	4	4
Price Risk Derivative Liabilities, at Fair Value	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	10	15
Price Risk Derivative Liabilities, at Fair Value	(21)	(6)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value	10	15
Price Risk Derivative Liabilities, at Fair Value	(21)	(6)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	5	9
Price Risk Derivative Liabilities, at Fair Value	(7)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value	5	9
Price Risk Derivative Liabilities, at Fair Value	(7)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 2 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 3 | Future [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	30	22
Price Risk Derivative Liabilities, at Fair Value	(28)	(22)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	0
Price Risk Derivative Liabilities, at Fair Value	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Call Option [Member]
Price Risk Derivative Assets, at Fair Value	3
Price Risk Derivative Liabilities, at Fair Value		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value		3
Price Risk Derivative Liabilities, at Fair Value		(2)
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	0
Price Risk Derivative Liabilities, at Fair Value	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 | Call Option [Member]
Price Risk Derivative Assets, at Fair Value	3
Price Risk Derivative Liabilities, at Fair Value		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 | Future [Member]
Price Risk Derivative Assets, at Fair Value		3
Price Risk Derivative Liabilities, at Fair Value		(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	30	22
Price Risk Derivative Liabilities, at Fair Value	(28)	(22)
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 | Call Option [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 | Future [Member]
Price Risk Derivative Assets, at Fair Value		0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 | 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 3 | Call Option [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	76	99
Price Risk Derivative Liabilities, at Fair Value	(88)	(89)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	76	99
Price Risk Derivative Liabilities, at Fair Value	(88)	(89)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0	0
Price Risk Derivative Liabilities, at Fair Value	$ 0	$ 0

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Fair Value Measurements Table - Reconciliation of Level 3 Derivatives (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Net unrealized gains included in other income (expense)	$ (4)
Level 3 | Fair Value, Measurements, Recurring [Member]
Balance, December 31, 2015	(5)
Balance, June 30, 2016	$ (9)

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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		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Net Income	$ 424	$ 772	$ 760	$ 993
Less: Income attributable to noncontrolling interest	183	474	207	411
Net Income, net of noncontrolling interest	241	298	553	582
Less: General Partner’s interest in income	1	0	2	1
Convertible Unitholders' interest in income	1	0	1	0
Less: Class D Unitholder’s interest in income	0	0	0	1
Income available to Limited Partners	$ 239	$ 298	$ 550	$ 580
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,048.9	1,076.0	1,046.9	1,077.2
Basic income per Limited Partner unit	$ 0.23	$ 0.28	$ 0.53	$ 0.54
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and distributions to Convertible Unitholders	$ (1)	$ (1)	$ (1)	$ (1)
Diluted income available to Limited Partners	$ 240	$ 299	$ 551	$ 581
Dilutive effect of unconverted unit awards and Convertible Units	14.9	1.6	5.6	1.8
Diluted weighted average limited partner units	1,063.8	1,077.6	1,052.5	1,079.0
Diluted income per Limited Partner unit	$ 0.23	$ 0.28	$ 0.52	$ 0.54

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Debt Obligations Narrative (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Apr. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Aug. 01, 2016
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt		$ 12,048	$ 15,466
Parent Company [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt		145	$ 2,972
ETE Senior Secured Revolving Credit Facilities [Member] | Parent Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		1,500
Line of Credit Facility, Amount Outstanding		885
Line of Credit Facility, Remaining Borrowing Capacity		615
Term loan due 2019 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Senior Notes		2,035
Secured Debt		1,200
Line of Credit Facility, Maximum Borrowing Capacity		2,035
6.25% Senior Notes due 2021 [Member] | Sunoco LP [Member]
Debt Instrument [Line Items]
Senior Notes	$ 800	$ 800
Debt Instrument, Interest Rate, Stated Percentage	6.25%	6.25%
Proceeds from Issuance of Long-term Debt	$ 789
ETP Revolving Credit Facility, due October 2017 [Member] | ETP [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 3,750
Line of Credit Facility, Amount Outstanding		1,130
Sunoco Logistics' $2.5 billion revolving credit facility due March 2020 [Member] | Sunoco Logistics [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		2,500
Line of Credit Facility, Amount Outstanding		1,260
Line of Credit Facility, Maximum Borrowing Capacity		3,250
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
Line Of Credit Facility, Additional Borrowing Capacity Subject To Lender Approval		250
Line of Credit Facility, Amount Outstanding		675
Letters of Credit Outstanding, Amount		22
Assumed from Regency [Member]
Debt Instrument [Line Items]
Senior Notes		3,800
6.125% Senior Notes, due May 15, 2016 [Member] | Sunoco Logistics [Member]
Debt Instrument [Line Items]
Senior Notes		$ 175
Debt Instrument, Interest Rate, Stated Percentage		6.125%
3.90% Senior Notes Due July 15, 2026 [Member] | Sunoco Logistics [Member]
Debt Instrument [Line Items]
Senior Notes		$ 550
Debt Instrument, Interest Rate, Stated Percentage		3.90%
Subsequent Event [Member] | Bakken Pipeline [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 2,500

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Equity Narrative (Details) - USD ($)	1 Months Ended		3 Months Ended			6 Months Ended			12 Months Ended
	Aug. 31, 2016	Mar. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jul. 31, 2016
Relinquishment of Incentive Distributions			$ 75,000,000
Gains (losses) from subsidiary common unit issuances, net							$ (12,000,000)	$ 50,000,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan							3,100,000
Stock Issued During Period, Shares, New Issues							0
Ratio of Convertible Units to Common Units			31.50%				31.50%
Convertible Unit Distribution to ETE Common Unit Distribution, Percent			40.00%				40.00%
Conversion Price of Preferred Units			$ 6.56				$ 6.56
Stock Repurchase Program, Remaining Authorized Repurchase Amount			936,000,000				936,000,000
Subsidiary units issued							1,075,000,000
Preferred Units, Preferred Partners' Capital Accounts			$ 59,000,000		$ 0		59,000,000
Parent Company [Member]
Rate			$ 0.2850	$ 0.2850	$ 0.2850
Preferred Units, Preferred Partners' Capital Accounts			$ 59,000,000		$ 0		59,000,000
ETP [Member]
Stock Issued During Period, Value, Dividend Reinvestment Plan							$ 84,000,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan			8,400,000				8,400,000
Rate			$ 1.0550	1.0550	$ 1.0550
Sunoco Logistics [Member]
Rate			0.5000	0.4890	0.4790
Sunoco LP [Member]
Stock Issued During Period, Shares, New Issues							2,300,000
Rate			$ 825,500	$ 0.8173	$ 0.8013
Business Combination, Consideration Transferred							$ 114,000,000
Kelcy L. Warren [Member] | ETE [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest							18.00%
Equity distribution agreement [Member] | ETP [Member]
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount			$ 0				$ 0
Proceeds from Issuance of Common Stock, net							324,000,000
Fees and Commissions							3,000,000
Equity distribution agreement [Member] | Sunoco Logistics [Member]
Proceeds from Issuance of Common Limited Partners Units							667,000,000
Fees and Commissions							$ 7,000,000
Messrs. McReynolds, Ramsey and McCrea [Member] | ETE [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest							2.20%
Mr. Ray Davis [Member] | ETE [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest							6.90%
Mr. Ray Davis [Member] | LE GP, LLC [Member]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest							18.80%
Bakken Pipeline Transaction [Member] | ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							36.75%
Common Unitholders
Subsidiary units issued							$ (12,000,000)
Convertible Preferred Stock [Member]
Stock Issued During Period, Shares, New Issues							329,300,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit			$ 0.11
Convertible Preferred Stock [Member] | Kelcy L. Warren [Member]
Stock Issued During Period, Shares, New Issues							187,313,942
Convertible Preferred Stock [Member] | Mr. McReynolds [Member]
Stock Issued During Period, Shares, New Issues							21,382,155
Convertible Preferred Stock [Member] | Mr. Ramsey [Member]
Stock Issued During Period, Shares, New Issues							51,317
Convertible Preferred Stock [Member] | Mr. McCrea [Member]
Stock Issued During Period, Shares, New Issues							1,112,728
Convertible Preferred Stock [Member] | Mr. Ray Davis [Member]
Stock Issued During Period, Shares, New Issues							72,042,486
Class C Units [Member] | Sunoco LP [Member]
Stock Issued During Period, Shares, New Issues							16,400,000
Class C Units [Member] | Aloha Contribution [Member] | Sunoco LP [Member]
Stock Issued During Period, Shares, New Issues							5,200,000
Class C Units [Member] | Class A Unit Exchange [Member] | Sunoco LP [Member]
Stock Issued During Period, Shares, New Issues							11,200,000
Dropdown of Sunoco LLC Interest [Member] | Sunoco LP [Member]
Business Combination, Consideration Transferred		$ 2,230,000,000
Payments to Acquire Businesses, Gross		$ 2,200,000,000
Sale of Stock, Number of Shares Issued in Transaction		5,700,000
Dropdown of Sunoco LLC Interest [Member] | Sunoco, LLC [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		68.42%
Dropdown of Sunoco LLC Interest [Member] | Legacy Sunoco, Inc. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Subsequent Event [Member]
Relinquishment of Incentive Distributions						$ 249,000,000			$ 95,000,000	$ 105,000,000	$ 593,000,000
Subsequent Event [Member] | Equity distribution agreement [Member] | ETP [Member]
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount												$ 1,500,000,000
Subsequent Event [Member] | Bakken Pipeline Transaction [Member]
Business Combination, Consideration Transferred	$ 2,000,000,000
Subsequent Event [Member] | Bakken Pipeline Transaction [Member] | ETP [Member]
Proceeds from Sale of Equity Method Investments	1,200,000,000
Subsequent Event [Member] | Bakken Pipeline Transaction [Member] | Sunoco Logistics [Member]
Proceeds from Sale of Equity Method Investments	$ 800,000,000
Subsequent Event [Member] | Bakken Pipeline Transaction [Member] | ETP and Sunoco Logistics [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	38.25%

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Equity Table - Change In ETE Common Units (Details) shares in Millions	6 Months Ended
	Jun. 30, 2016 shares
Class of Stock [Line Items]
Outstanding at December 31, 2015	1,044.8
Stock Issued During Period, Shares, New Issues	0.0
Outstanding at June 30, 2016	1,044.8
Convertible Preferred Stock [Member]
Class of Stock [Line Items]
Outstanding at December 31, 2015	0.0
Stock Issued During Period, Shares, New Issues	329.3
Outstanding at June 30, 2016	329.3

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Equity Table - Quarterly Distributions of Available Cash (Details) - $ / shares	3 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Sunoco Logistics [Member]
Record Date	Aug. 08, 2016	May 09, 2016	Feb. 08, 2016
Payment Date	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016
Rate	$ 0.5000	$ 0.4890	$ 0.4790
Parent Company [Member]
Record Date	Aug. 08, 2016	May 06, 2016	Feb. 04, 2016
Payment Date	Aug. 19, 2016	May 19, 2016	Feb. 19, 2016
Rate	$ 0.2850	$ 0.2850	$ 0.2850
ETP [Member]
Record Date	Aug. 08, 2016	May 06, 2016	Feb. 08, 2016
Payment Date	Aug. 15, 2016	May 16, 2016	Feb. 16, 2016
Rate	$ 1.0550	$ 1.0550	$ 1.0550
Sunoco LP [Member]
Record Date	Aug. 05, 2016	May 06, 2016	Feb. 05, 2016
Payment Date	Aug. 15, 2016	May 16, 2016	Feb. 16, 2016
Rate	$ 825,500	$ 0.8173	$ 0.8013

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Equity Table - IDR Schedule (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Relinquishment of Incentive Distributions	$ 75
Subsequent Event [Member]
Relinquishment of Incentive Distributions		$ 249	$ 95	$ 105	$ 593

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Equity Table - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 5	$ 0
Foreign currency translation adjustment	(5)	(4)
Actuarial loss related to pensions and other postretirement benefits	5	8
AOCI attributable to equity method investments	(11)	0
Subtotal	(6)	4
Amounts attributable to noncontrolling interest	6	(4)
Accumulated other comprehensive income, net	$ 0	$ 0

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Income Taxes (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Mar. 31, 2016	Jun. 30, 2016
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 11
Sunoco, LLC [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	68.42%
Legacy Sunoco, Inc. [Member] | Dropdown of Sunoco LLC Interest [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details)	1 Months Ended	3 Months Ended			6 Months Ended
	Jan. 31, 2012 USD ($)	Jun. 30, 2016 USD ($) sites	Mar. 31, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) sites	Jun. 30, 2015 USD ($)	Apr. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)
Lease Expiration Date					Dec. 31, 2058
Operating Leases, Rent Expense, Contingent Rentals		$ 7,000,000	$ 9,000,000	$ 6,000,000		$ 10,000,000
Loss Contingency Accrual, at Carrying Value		59,000,000			$ 59,000,000			$ 40,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed		0			0
Payments for Environmental Liabilities		$ 11,000,000		$ 11,000,000	$ 19,000,000	$ 18,000,000
Site Contingency, Number of Sites Needing Remediation | sites		19			19
Environmental Costs Recognized, Recovery Credited to Expense					$ 19,000,000
Accrual for Environmental Loss Contingencies		$ 365,000,000			365,000,000			$ 368,000,000
Proposed Environmental Penalty		200,000			200,000
Supplemental Environmental Project [Member]
Proposed Environmental Penalty		21,000			21,000
Compensatory Damages [Member]
Gain Contingency, Unrecorded Amount		319,000,000			319,000,000
Disgorgement [Member]
Gain Contingency, Unrecorded Amount		595,000,000			595,000,000
Expense Reimbursement [Member]
Gain Contingency, Unrecorded Amount		1,000,000			1,000,000
Final Judgement [Member]
Gain Contingency, Unrecorded Amount		536,000,000			536,000,000
Proposed WMB Merger [Member]
Loss on Contract Termination for Default					1,480,000,000
New Mexico Environmental Department [Member]
Accrual for Environmental Loss Contingencies		250,000			250,000
Texas Commission on Environmental Quality [Member]
Accrual for Environmental Loss Contingencies		300,000			300,000
TCEQ [Member]
Proposed Environmental Penalty		21,000			$ 21,000
AmeriGas [Member]
Contingent Residual Support Agreement, Amount	$ 1,550,000,000	$ 1,000,000,000
Sunoco LP [Member] | 6.375% Senior Notes due April 2023 [Member]
Debt Instrument, Interest Rate, Stated Percentage		6.375%			6.375%
Senior Notes		$ 800,000,000			$ 800,000,000
Sunoco LP [Member] | 6.25% Senior Notes due 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage		6.25%			6.25%		6.25%
Senior Notes		$ 800,000,000			$ 800,000,000		$ 800,000,000
Sunoco LP [Member] | Term loan due 2019 [Member]
Senior Notes		$ 2,035,000,000			$ 2,035,000,000
Sunoco, Inc. [Member]
Loss Contingency, Pending Claims, Number		5			5
Sunoco, Inc. [Member] | Multidistrict Legislation [Member]
Loss Contingency, Pending Claims, Number		4			4
Southern Union [Member]
Percentage Of Recovery					50.00%
Loss Contingency, Estimated Recovery from Third Party					150000
Sunoco [Member]
Site Contingency, Number of Sites Needing Remediation		49			49

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Environmental Exit Cost [Line Items]
Current	$ 42	$ 42
Non-current	323	326
Total environmental liabilities	$ 365	$ 368

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Rent expense table (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Rental expense(1)	[1]	$ 57	$ 54	$ 108	$ 106
Less: Sublease rental income		(5)	(4)	(12)	(12)
Rental expense, net		$ 52	$ 50	$ 96	$ 94

[1] Includes contingent rentals totaling $7 million and $6 million for the three months ended June 30, 2016 and 2015, respectively, and $9 million and $10 million for the six months ended June 30, 2016 and 2015, respectively.

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Derivative Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)		6 Months Ended	12 Months Ended
		Jun. 30, 2016 bushels barrels Megawatt bbl MMbtu	Dec. 31, 2015 bushels barrels Megawatt bbl MMbtu
Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Corn [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Power [Member]
Maximum Term Of Commodity Derivatives			2016
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2018	2018
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Forwards Swaps [Member] | Natural Gas Liquids and Crude [Member]
Maximum Term Of Commodity Derivatives			2018
Mark-To-Market Derivatives [Member] | Maximum [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Forwards Swaps [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2017	2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Future [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2017
Mark-To-Market Derivatives [Member] | Maximum [Member] | Trading [Member] | Future [Member] | Crude Oil [Member]
Maximum Term Of Commodity Derivatives		2017
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Forwards Swaps [Member] | Natural Gas Liquids and Crude [Member]
Maximum Term Of Commodity Derivatives			2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Forwards Swaps [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2016	2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Future [Member] | Power [Member]
Maximum Term Of Commodity Derivatives		2016
Mark-To-Market Derivatives [Member] | Minimum [Member] | Trading [Member] | Future [Member] | Crude Oil [Member]
Maximum Term Of Commodity Derivatives		2016
Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives			2016
Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives			2016
Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives			2016
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017
Fair Value Hedging [Member] | Maximum [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2017
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016
Fair Value Hedging [Member] | Minimum [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Natural Gas [Member]
Maximum Term Of Commodity Derivatives		2016
Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Notional Volume		522,500	6,522,500
Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Notional Volume		3,835,000	14,380,000
Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forwards Swaps [Member] | Natural Gas Liquids and Crude [Member]
Notional Volume | bbl		10,443,400	8,146,800
Maximum Term Of Commodity Derivatives		2016
Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Refined Products [Member]
Notional Volume | barrels		1,784,000	1,289,000
Short [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Corn [Member]
Notional Volume | bushels		1,635,000
Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Notional Volume	[1]		31,240,000
Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Notional Volume			602,500
Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Power [Member]
Notional Volume | Megawatt		424,000
Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Power [Member]
Notional Volume | Megawatt		320,257	109,791
Short [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Future [Member] | Crude Oil [Member]
Notional Volume | Megawatt		222,000	591,000
Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Notional Volume		42,167,500	37,555,000
Short [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Notional Volume		42,167,500	37,555,000
Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Swing Swaps IFERC [Member] | Natural Gas [Member]
Notional Volume		34,465,000	71,340,000
Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Forward Physical Contracts [Member] | Natural Gas [Member]
Notional Volume		3,838,458	21,922,484
Long [Member] | Mark-To-Market Derivatives [Member] | Non Trading [Member] | Future [Member] | Corn [Member]
Notional Volume | bushels			1,185,000
Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Basis Swaps IFERC/NYMEX [Member] | Natural Gas [Member]
Notional Volume	[1]	7,920,000
Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Fixed Swaps/Futures [Member] | Natural Gas [Member]
Notional Volume		5,825,000
Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Options - Puts [Member] | Power [Member]
Notional Volume | Megawatt			260,534
Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Call Option [Member] | Power [Member]
Notional Volume | Megawatt		696,000	1,300,647
Long [Member] | Mark-To-Market Derivatives [Member] | Trading [Member] | Forwards Swaps [Member] | Power [Member]
Notional Volume | Megawatt		272,164	357,092
Long [Member] | Fair Value Hedging [Member] | Non Trading [Member] | Hedged Item - Inventory (MMBtu) [Member] | Natural Gas [Member]
Notional Volume		42,167,500	37,555,000

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

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Derivative Assets And Liabilities Table - Interest Rate Swaps Outstanding (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
July 2016 [Member]
Notional Amount	[1],[2]	$ 0	$ 200
Type	[1],[2],[3]	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate
July 2017 [Member]
Notional Amount	[1],[4]	$ 500	300
Type	[1],[3],[4]	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate
July 2018 [Member]
Notional Amount	[4]	$ 200	200
Type	[3],[4]	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate
March 2019 [Member]
Notional Amount		$ 300	300
Type	[3]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
July 2019 [Member]
Notional Amount	[4]	$ 200	200
Type	[3],[4]	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate
December 2018 [Member]
Notional Amount		$ 1,200	$ 1,200
Type	[3]	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%

[1] ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million. In June 2016, ETP extended the expiration of those swaps to July 2017.

[2] Represents the effective date. These forward-starting swaps have a term of 10 and 30 years with a mandatory termination date the same as the effective date.

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

[4] Represents the effective date. These forward-starting swaps have terms 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	Jun. 30, 2016	Dec. 31, 2015
Total derivatives assets	$ 222	$ 454
Total derivatives liabilities	(601)	(532)
Designated as Hedging Instrument [Member]
Total derivatives assets	0	38
Total derivatives liabilities	(4)	(3)
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	0	38
Total derivatives liabilities	(4)	(3)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	222	416
Total derivatives liabilities	(597)	(529)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	138	353
Total derivatives liabilities	(173)	(306)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	55	63
Total derivatives liabilities	(57)	(47)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	29	0
Total derivatives liabilities	(9)	(171)
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ (358)	$ (5)

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Derivative Assets And Liabilities Table - Gross FV and Netting Offset (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 222	$ 454
Derivative Liability, Fair Value, Gross Liability	(601)	(532)
Counterparty netting	(28)	(17)
Counterparty netting	28	17
Payments on margin deposit	(138)	(309)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	138	309
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	56	128
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(435)	(206)
Without offsetting agreements [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	29	0
Derivative Liability, Fair Value, Gross Liability	(367)	(176)
OTC Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	55	63
Derivative Liability, Fair Value, Gross Liability	(57)	(47)
Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	138	391
Derivative Liability, Fair Value, Gross Liability	$ (177)	$ (309)

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Derivative Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Recognized OCI on Derivatives (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ 0	$ 0	$ 1
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ 0	$ 0	$ 1

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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		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness	$ 21	$ 11	$ 17	$ 8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(145)	83	(216)	(2)
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(7)	(6)	(16)	(8)
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	21	11	17	8
Amount of Gain/(Loss) Recognized in Income on Derivatives	(53)	(40)	(45)	(48)
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(81)	127	(151)	50
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (4)	$ 2	$ (4)	$ 4

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Related Party Transactions Related Party Revenue (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transactions [Abstract]
Revenue from Related Parties	$ 45	$ 130	$ 126	$ 206

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Reportable Segments Table - Segment Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ 1,385	$ 1,512	$ 2,963	$ 2,904
Depreciation, depletion and amortization	588	514	1,150	1,007
Interest expense, net	450	408	877	779
Gains (losses) on interest rate derivatives	(81)	127	(151)	50
Non-cash unit-based compensation expense	(22)	(25)	(23)	(48)
Unrealized losses on commodity risk management activities	(24)	(44)	(84)	(119)
Losses on extinguishments of debt	0	(33)	0	(33)
Inventory valuation adjustments	181	184	168	150
Equity in earnings of unconsolidated affiliates	95	117	156	174
Adjusted EBITDA related to unconsolidated affiliates	(127)	(215)	(346)	(361)
Other, net	(46)	(15)	(40)	(18)
INCOME BEFORE INCOME TAX BENEFIT	415	716	696	949
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	1,370	1,488	2,782	2,854
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	164	142	323	271
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	44	49	88	98
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	(68)	(25)	(105)	(48)
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Segment Adjusted EBITDA	$ (125)	$ (142)	$ (125)	$ (271)

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Reportable Segments Table - Segment Assets (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Assets	$ 74,560	$ 71,189
Investment In ETP [Member]
Assets	66,041	65,173
Investment In Sunoco LP [Member]
Assets	8,762	8,842
Investment in Lake Charles LNG [Member]
Assets	1,437	1,369
Corporate and Other [Member]
Assets	656	638
Adjustments And Eliminations [Member]
Assets	$ (2,336)	$ (4,833)

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Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues	$ 9,344	$ 11,594	$ 17,026	$ 21,974
Investment In ETP [Member]
Revenues	5,289	11,540	9,770	21,866
Investment In Sunoco LP [Member]
Revenues	4,052	5,126	7,254	9,477
Adjustments And Eliminations [Member]
Revenues	(46)	(5,126)	(96)	(9,477)
Intersegment [Member] | Investment In ETP [Member]
Revenues	44	0	91	0
Intersegment [Member] | Investment In Sunoco LP [Member]
Revenues	2	0	5	0
External Customers [Member] | Investment In ETP [Member]
Revenues	5,245	11,540	9,679	21,866
External Customers [Member] | Investment In Sunoco LP [Member]
Revenues	4,050	5,126	7,249	9,477
External Customers [Member] | Investment in Lake Charles LNG [Member]
Revenues	$ 49	$ 54	$ 98	$ 108

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Reportable Segments Table - Revenues from External Customers by Segment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Revenues	$ 9,344	$ 11,594	$ 17,026	$ 21,974
Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	4,052	5,126	7,254	9,477
Investment In Sunoco LP [Member] | Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues	2,019	2,259	3,693	4,155
Investment In Sunoco LP [Member] | Wholesale Operations [Member]
Segment Reporting Information [Line Items]
Revenues	2,033	2,867	3,561	5,322
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	5,289	11,540	9,770	21,866
Investment In ETP [Member] | Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Revenues	229	239	483	510
Investment In ETP [Member] | Midstream [Member]
Segment Reporting Information [Line Items]
Revenues	690	767	1,217	1,516
Investment In ETP [Member] | Liquids Transportation And Services [Member]
Segment Reporting Information [Line Items]
Revenues	1,099	783	1,928	1,595
Investment In ETP [Member] | Investment in Sunoco Logistics [Member]
Segment Reporting Information [Line Items]
Revenues	2,250	3,120	3,979	5,646
Investment In ETP [Member] | Retail Marketing [Member]
Segment Reporting Information [Line Items]
Revenues	0	5,557	0	10,339
Investment In ETP [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	593	588	1,289	1,233
Investment In ETP [Member] | Intrastate Transportation And Storage [Member]
Segment Reporting Information [Line Items]
Revenues	428	486	874	1,027
Intersegment [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	2	0	5	0
Intersegment [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	44	0	91	0
External Customers [Member] | Investment In Sunoco LP [Member]
Segment Reporting Information [Line Items]
Revenues	4,050	5,126	7,249	9,477
External Customers [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	$ 5,245	$ 11,540	$ 9,679	$ 21,866

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Supplemental Financial Statement Information Table - Balance Sheets (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Cash and cash equivalents	$ 475	$ 606	$ 1,623	$ 847
Accounts receivable from related companies	60	119
Other current assets	644	603
Total current assets	6,090	5,410
Property, plant and equipment, net	51,386	48,683
Advances to and investments in unconsolidated affiliates	3,453	3,462
Intangible assets, net	5,356	5,431
Goodwill	7,515	7,473
Other non-current assets, net	742	730
Total assets	74,560	71,189
Accounts payable	2,931	2,274
Accounts payable to related companies	20	28
Accrued and other current liabilities	2,195	2,408
Total current liabilities	6,188	4,910
Long-term debt, less current maturities	38,501	36,837
Note payable to related company	107	0
Other non-current liabilities	1,137	1,069
Commitments and contingencies
General Partner	(2)	(2)
Common Unitholders	(1,738)	(952)
Class D Units	0	22
Total partners’ capital	(1,681)	(932)
Total liabilities and equity	74,560	71,189
Preferred Units, Preferred Partners' Capital Accounts	59	0
Parent Company [Member]
Cash and cash equivalents	1	1	$ 1	$ 2
Accounts receivable from related companies	41	34
Other current assets	1	0
Total current assets	43	35
Property, plant and equipment, net	35	20
Advances to and investments in unconsolidated affiliates	5,074	5,764
Intangible assets, net	3	6
Goodwill	9	9
Other non-current assets, net	10	10
Total assets	5,174	5,844
Accounts payable	1	0
Accounts payable to related companies	58	111
Interest payable	66	66
Accrued and other current liabilities	13	1
Total current liabilities	138	178
Long-term debt, less current maturities	6,362	6,332
Note payable to related company	353	265
Other non-current liabilities	2	1
Commitments and contingencies
General Partner	(2)	(2)
Common Unitholders	(1,738)	(952)
Class D Units	0	22
Total partners’ capital	(1,681)	(932)
Total liabilities and equity	5,174	5,844
Preferred Units, Preferred Partners' Capital Accounts	$ 59	$ 0

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Supplemental Financial Statement Information Schedule of Statements of Operations (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)		$ (187)	$ (183)	$ (343)	$ (338)
Interest expense, net		(450)	(408)	(877)	(779)
Equity in earnings of unconsolidated affiliates		95	117	156	174
Other, net		24	17	40	24
Income tax benefit		(9)	(56)	(64)	(44)
NET INCOME		241	298	553	582
General Partner’s interest in net income		1	0	(2)	(1)
Convertible Unitholders' interest in income		1	0	1	0
Class D Unitholder’s interest in net income		0	0	0	1
Limited Partners’ interest in net income		239	298	550	580
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES(1)	[1]	(44)	(29)	(81)	(57)
Interest expense, net		(82)	(72)	(163)	(133)
Equity in earnings of unconsolidated affiliates		369	398	799	771
Other, net		(2)	0	(2)	1
INCOME BEFORE INCOME TAXES		241	297	553	582
Income tax benefit		0	(1)	0	0
NET INCOME		241	298	553	582
General Partner’s interest in net income		1	0	(2)	(1)
Convertible Unitholders' interest in income		1	0	1	0
Class D Unitholder’s interest in net income		0	0	0	1
Limited Partners’ interest in net income		$ 239	$ 298	$ 550	$ 580

[1] Includes management fees paid by ETE to ETP.

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Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 1,518	$ 1,113
Cash paid for Bakken Pipeline Transaction	(116)	(475)
Contributions to unconsolidated affiliate	30	43
Capital expenditures	(3,723)	(4,181)
Net cash used in investing activities	(3,775)	(4,673)
Proceeds from borrowings	12,048	15,466
Repayments of long-term debt	(9,551)	(11,301)
Proceeds from affiliate	161	398
Distributions to partners	(540)	(509)
Units repurchased under buyback program	0	294
Debt issuance costs	(29)	(61)
Net cash provided by financing activities	2,126	4,336
INCREASE IN CASH AND CASH EQUIVALENTS	(131)	776
Cash and cash equivalents, beginning of period	606	847
Cash and cash equivalents, end of period	475	1,623
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	507	475
Cash paid for Bakken Pipeline Transaction	0	(817)
Contributions to unconsolidated affiliate	65	0
Capital expenditures	(15)	(7)
Net cash used in investing activities	(80)	(824)
Proceeds from borrowings	145	2,972
Repayments of long-term debt	(120)	(1,915)
Proceeds from affiliate	88	106
Distributions to partners	(540)	(509)
Units repurchased under buyback program	0	294
Debt issuance costs	0	(12)
Net cash provided by financing activities	(427)	348
INCREASE IN CASH AND CASH EQUIVALENTS	0	(1)
Cash and cash equivalents, beginning of period	1	2
Cash and cash equivalents, end of period	$ 1	$ 1