10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2014

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.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(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 October 31, 2014, the registrant had 538,766,899 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	46
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	64
ITEM 4. CONTROLS AND PROCEDURES	67
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	68
ITEM 1A. RISK FACTORS	68
ITEM 6. EXHIBITS	68
SIGNATURE	69

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, 2013 filed with the Securities and Exchange Commission on February 27, 2014.

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 Corp., which owns 100% of FGT
CrossCountry	CrossCountry Energy LLC, which owns an indirect 50% interest in Citrus
Eagle Rock	Eagle Rock Energy Partners, L.P.
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 Credit Facility	ETP’s $2.5 billion revolving credit facility
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.
Holdco	ETP Holdco Corporation
Hoover	Hoover Energy Partners, LP
IDRs	incentive distribution rights
Lake Charles LNG	Lake Charles LNG Company, LLC
LIBOR	London Interbank Offered Rate

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LNG	liquefied natural gas
Lone Star	Lone Star NGL LLC
MACS	Mid-Atlantic Convenience Stores, 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
PEPL Holdings	PEPL Holdings, LLC, a wholly-owned subsidiary of ETP
PES	Philadelphia Energy Solutions
PHMSA	Pipeline Hazardous Materials Safety Administration
PVR	PVR Partners, L.P.
Regency	Regency Energy Partners LP
Regency Credit Facility	Regency’s $1.5 billion revolving credit facility
Regency Preferred Units	Regency’s Series A Convertible Preferred Units, the Preferred Units of a Subsidiary
SEC	Securities and Exchange Commission
Southern Union	Southern Union Company
SUGS	Southern Union Gas Services
Sunoco	Sunoco, Inc.
Sunoco Logistics	Sunoco Logistics Partners L.P.
Susser	Susser Holdings Corporation
Transwestern	Transwestern Pipeline Company, LLC
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, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

iii

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	September 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,108		$	590
Accounts receivable, net	4,722			3,658
Accounts receivable from related companies	51			63
Inventories	1,780			1,807
Exchanges receivable	58			67
Price risk management assets	16			39
Other current assets	307			312
Total current assets	8,042			6,536
PROPERTY, PLANT AND EQUIPMENT	43,017			33,917
ACCUMULATED DEPRECIATION	(4,280		)	(3,235		)
	38,737			30,682
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,633			4,014
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	1			18
GOODWILL	7,867			5,894
INTANGIBLE ASSETS, net	5,504			2,264
OTHER NON-CURRENT ASSETS, net	897			922
Total assets	$	64,681		$	50,330

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

1

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)

	September 30, 2014			December 31, 2013
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	4,694		$	3,834
Accounts payable to related companies	6			14
Exchanges payable	269			284
Price risk management liabilities	9			53
Accrued and other current liabilities	2,108			1,678
Current maturities of long-term debt	1,345			637
Total current liabilities	8,431			6,500
LONG-TERM DEBT, less current maturities	28,508			22,562
DEFERRED INCOME TAXES	4,230			3,865
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	112			73
OTHER NON-CURRENT LIABILITIES	1,060			1,019
COMMITMENTS AND CONTINGENCIES (Note 13)
PREFERRED UNITS OF SUBSIDIARY	32			32
REDEEMABLE NONCONTROLLING INTEREST	15			—
EQUITY:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	687			1,066
Class D Units	18			6
Accumulated other comprehensive income	5			9
Total partners’ capital	709			1,078
Noncontrolling interest	21,584			15,201
Total equity	22,293			16,279
Total liabilities and equity	$	64,681		$	50,330

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

2

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
REVENUES:
Natural gas sales	$	1,290		$	915		$	4,082		$	2,752
NGL sales	1,797			968			4,451			2,468
Crude sales	4,497			4,215			13,022			11,408
Gathering, transportation and other fees	958			786			2,708			2,341
Refined product sales	5,165			4,633			14,581			13,945
Other	1,280			969			3,366			2,814
Total revenues	14,987			12,486			42,210			35,728
COSTS AND EXPENSES:
Cost of products sold	13,015			11,064			36,808			31,436
Operating expenses	540			419			1,359			1,178
Depreciation, depletion and amortization	425			332			1,248			962
Selling, general and administrative	185			142			490			448
Total costs and expenses	14,165			11,957			39,905			34,024
OPERATING INCOME	822			529			2,305			1,704
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(356		)	(298		)	(1,015		)	(913		)
Equity in earnings of unconsolidated affiliates	84			38			265			182
Gains (losses) on extinguishment of debt	2			—			2			(7		)
Gains (losses) on interest rate derivatives	(25		)	3			(73		)	55
Gain on sale of AmeriGas common units	14			87			177			87
Other, net	(15		)	33			(38		)	—
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	526			392			1,623			1,108
Income tax expense from continuing operations	56			49			271			136
INCOME FROM CONTINUING OPERATIONS	470			343			1,352			972
Income from discontinued operations	—			13			66			44
NET INCOME	470			356			1,418			1,016
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	282			205			898			648
NET INCOME ATTRIBUTABLE TO PARTNERS	188			151			520			368
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1			1			1
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	—			—			1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	188		$	150		$	518		$	367
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.35		$	0.26		$	0.94		$	0.62
Diluted	$	0.35		$	0.26		$	0.93		$	0.62
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.35		$	0.27		$	0.95		$	0.65
Diluted	$	0.35		$	0.27		$	0.94		$	0.65

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net income	$	470		$	356		$	1,418		$	1,016
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	—			(3		)	6			(5		)
Change in value of derivative instruments accounted for as cash flow hedges	3			(4		)	(3		)	4
Change in value of available-for-sale securities	1			1			1			1
Actuarial gain (loss) relating to pension and other postretirement benefits	(1		)	8			(2		)	9
Foreign currency translation adjustments	(1		)	—			(3		)	(1		)
Change in other comprehensive income from unconsolidated affiliates	—			9			(6		)	13
	2			11			(7		)	21
Comprehensive income	472			367			1,411			1,037
Less: Comprehensive income attributable to noncontrolling interest	285			213			895			660
Comprehensive income attributable to partners	$	187		$	154		$	516		$	377

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

4

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014

(Dollars in millions)

(unaudited)

	General Partner			Common Unitholders			Class D Units			Accumulated Other Comprehensive Income			Non- controlling Interest			Total
Balance, December 31, 2013	$	(3	)	$	1,066		$	6		$	9		$	15,201		$	16,279
Distributions to partners	(1		)	(593		)	(2		)	—			—			(596		)
Distributions to noncontrolling interest	—			—			—			—			(1,359		)	(1,359		)
Subsidiary units issued for cash	—			106			2			—			1,773			1,881
Subsidiary units issued in certain acquisitions	—			211			—			—			5,382			5,593
Subsidiary units redeemed in Lake Charles LNG Transaction	2			480			—			—			(482		)	—
Purchase of additional Regency Units	—			(99		)	—			—			99			—
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			11			—			47			58
Capital contributions received from noncontrolling interest	—			—			—			—			19			19
Other, net	—			(2		)	—			—			9			7
Units repurchased under buyback program	—			(1,000		)	—			—			—			(1,000		)
Other comprehensive loss, net of tax	—			—			—			(4		)	(3		)	(7		)
Net income	1			518			1			—			898			1,418
Balance, September 30, 2014	$	(1	)	$	687		$	18		$	5		$	21,584		$	22,293

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

5

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Nine Months Ended September 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,418		$	1,016
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,248			962
Deferred income taxes	(66		)	244
Amortization included in interest expense	(41		)	(43		)
Non-cash compensation expense	60			43
Gain on sale of AmeriGas common units	(177		)	(87		)
Losses on disposal of assets	13			—
(Gains) losses on extinguishment of debt	(2		)	7
LIFO valuation adjustments	17			(22		)
Equity in earnings of unconsolidated affiliates	(265		)	(182		)
Distributions from unconsolidated affiliates	224			269
Other non-cash	(42		)	22
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation	120			(382		)
Net cash provided by operating activities	2,507			1,847
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(1,794		)	(5		)
Cash proceeds from the sale of AmeriGas common units	814			346
Capital expenditures (excluding allowance for equity funds used during construction)	(3,714		)	(2,504		)
Contributions in aid of construction costs	34			11
Contributions to unconsolidated affiliates	(264		)	(3		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	97			326
Proceeds from sale of discontinued operations	79			973
Proceeds from the sale of assets	22			72
Change in restricted cash	162			—
Other	(10		)	(49		)
Net cash used in investing activities	(4,574		)	(833		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	12,044			9,768
Repayments of long-term debt	(8,342		)	(9,439		)
Subsidiary equity offerings, net of issue costs	1,881			1,450
Distributions to partners	(596		)	(544		)
Debt issuance costs	(61		)	(56		)
Distributions to noncontrolling interest	(1,359		)	(1,050		)
Capital contributions received from noncontrolling interest	19			15
Redemption of Preferred Units	—			(340		)
Units repurchased under buyback program	(1,000		)	—
Other, net	(1		)	(13		)
Net cash provided by (used in) financing activities	2,585			(209		)
INCREASE IN CASH AND CASH EQUIVALENTS	518			805
CASH AND CASH EQUIVALENTS, beginning of period	590			372
CASH AND CASH EQUIVALENTS, end of period	$	1,108		$	1,177

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. OPERATIONS AND 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.

Our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names in September 2014 and October 2014, respectively, to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP, respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.

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

• the Parent Company;

• our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);

• ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDRs in ETP and Regency; and

• our wholly-owned subsidiary, Lake Charles LNG. Lake Charles LNG was acquired from ETP in February 2014.

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 Regency 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 18 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our activities are primarily conducted through our operating subsidiaries as follows:

• ETP is a publicly traded partnership whose operations are conducted through the following subsidiaries:

• ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through its Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.

• ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:

• Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.

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

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

7

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

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

• Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco. Panhandle and Sunoco operations are described as follows:

• Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 2, in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.

• Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and its wholly-owned subsidiary, Sunoco.

• Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.

• ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 44% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 2, in October 2014, Sunoco LP acquired MACS from ETP.

• Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading, and the management of coal and natural resource properties in the United States. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Its assets are primarily located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

• Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

Our financial statements reflect the following reportable business segments:

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

• Investment in Regency, including the consolidated operations of Regency.

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG.

• 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.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2013, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of September 30, 2014 and for the three and nine months ended September 30, 2014 and 2013 have been prepared in accordance with GAAP for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations

8

for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of September 30, 2014, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2014 and 2013. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on February 27, 2014.

Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity.

We record the collection of taxes to be remitted to government authorities on a net basis except for ETP’s retail marketing operations, in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and cost of products sold in the consolidated statements of operations, with no net impact on net income. Excise taxes collected by ETP’s retail marketing operations were $632 million and $581 million for the three months ended September 30, 2014 and 2013, respectively, and $1.74 billion and $1.66 billion for the nine months endedSeptember 30, 2014 and 2013, respectively.

New 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. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. 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 April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.

2. ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

2014

Susser Merger

On August 29, 2014, ETP and Susser completed the previously announced merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth.

In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.

Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.

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Summary of Assets Acquired and Liabilities Assumed

We accounted for the Susser Merger using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet as of September 30, 2014 reflected the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.

The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:

	Susser
Total current assets	$	422
Property, plant and equipment	1,065
Goodwill(1)	1,605
Intangible assets	481
Other non-current assets	27
	3,600
Current liabilities	377
Long-term debt, less current maturities	564
Deferred income taxes	432
Other non-current liabilities	40
Noncontrolling interest	404
	1,817
Total consideration	1,783
Cash received	67
Total consideration, net of cash received	$	1,716

⁽¹⁾  None of the goodwill is expected to be deductible for tax purposes.

ETP incurred merger related costs related to the Susser Merger of $24 million during the three months ended September 30, 2014. Our consolidated statements of operations for the three and nine months endedSeptember 30, 2014 reflected revenue and net income related to Susser of $575 million and $2 million, respectively.

No pro forma information has been presented for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations.

MACS to Sunoco LP

On October 1, 2014, Sunoco LP acquired MACS from ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with net proceeds of $359 million from a public offering of 8 million Sunoco LP common units.

Aloha Petroleum Acquisition

On September 25, 2014, Sunoco LP entered into a definitive agreement to acquire Honolulu, Hawaii-based Aloha Petroleum, Ltd (“Aloha Petroleum”). Aloha Petroleum is an independent gasoline marketer and convenience store operator in Hawaii, with an extensive wholesale fuel distribution network and six fuel storage terminals on the islands. The base purchase price for Aloha Petroleum is approximately $240 million, subject to post-closing earn-out, certain closing adjustments, and before transaction costs and expenses. The transaction is expected to close in the fourth quarter of 2014, subject to customary closing conditions and required consents and approvals.

10

Lake Charles LNG Transaction

On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). This transaction waseffective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG.

In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 10.

Panhandle Merger

On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and the Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units), and ETP (2.2 million common units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.

Regency’s Acquisition of Eagle Rock’s Midstream Business

On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% Senior Notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Regency is accounting for the Eagle Rock Midstream Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. This acquisition is expected to complement Regency’s core gathering and processing business and is expected to further diversify Regency’s geographic presence in the Mid-Continent region, East Texas and South Texas. Our consolidated statements of operations for the three and nine months ended September 30, 2014 included revenues and net income attributable to Eagle Rock’s operations of $472 million and $18 million, respectively.

Regency’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:

Assets	At July 1, 2014
Current assets	$	115
Property, plant and equipment	1,329
Other long-term assets	4
Total assets acquired	1,448
Liabilities
Current liabilities	109
Long-term debt	499
Long-term liabilities	12
Total liabilities assumed	620
Net assets acquired	$	828

Regency’s Acquisition of PVR

On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (“PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which

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was funded through borrowings under Regency’s revolving credit facility. The PVR Acquisition enhances Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. Regency accounted for the acquisition of PVR using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our statements of operations included revenues attributable to PVR of $302 million and $653 million for the three and nine months ended September 30, 2014, respectively. Our statements of operations included net income attributable to PVR of $84 million and $119 million for the three and nine months ended September 30, 2014, respectively.

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At March 21, 2014
Current assets	$	149
Property, plant and equipment	2,716
Investment in unconsolidated affiliates	62
Intangible assets (average useful lives of 30 years)	2,717
Goodwill	370
Other long-term assets	18
Total assets acquired	6,032
Liabilities
Current liabilities	168
Long-term debt	1,788
Premium related to senior notes	99
Long-term liabilities	30
Total liabilities assumed	2,085
Net assets acquired	$	3,947

Regency’s Acquisition of Hoover

On February 3, 2014, Regency acquired certain subsidiaries of Hoover for a total purchase price of $293 million, consisting of (i) 4,040,471 Regency Common Units issued to Hoover, (ii) $184 million in cash and (iii) $2 million in asset retirement obligations assumed (the “Hoover Acquisition”). The acquisition of Hoover increases Regency’s fee-based revenue, expanding its existing footprint in the southern portion of the Delaware Basin in West Texas, and its services to producers into crude and water gathering. A portion of the consideration is being held in escrow as security for certain indemnification claims. Regency financed the cash portion of the purchase price through borrowings under its revolving credit facility. Regency accounted for the acquisition of Hoover using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our statements of operations included revenues attributable to Hoover’s operations of $11 million and $26 million for the three and nine months ended September 30, 2014, respectively. Our statements of operations included net losses of $2 million and net income of $2 million attributable to Hoover’s operations for the three and nine months ended September 30, 2014, respectively.

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Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At February 3, 2014
Current assets	$	5
Property, plant and equipment	117
Intangible assets (average useful lives of 30 years)	148
Goodwill	30
Total assets acquired	300
Liabilities
Current liabilities	5
Asset retirement obligations	2
Total liabilities assumed	7
Net assets acquired	$	293

The fair values of the assets acquired and liabilities assumed for the Eagle Rock Midstream, PVR and Hoover acquisitions were determined using various valuation techniques, including the income and market approaches.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2014 and 2013 are presented as if the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assume there were no other changes in operations. This pro forma information does not necessarily reflect the actual results that would have occurred had the acquisitions occurred on January 1, 2013, nor is it indicative of future results of operations. Actual results for the three months ended September 30, 2014 include PVR and the Eagle Rock midstream business for the entire period.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenues	$	14,987	$	13,042	$	43,036	$	37,310
Net income attributable to partners	188		138		496		324
Basic net income per Limited Partner unit	$	0.35	$	0.25	$	0.91	$	0.58
Diluted net income per Limited Partner unit	$	0.35	$	0.25	$	0.91	$	0.58

The pro forma consolidated results of operations include adjustments to reflect incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting and incremental interest expense related to the financing of a portion of the purchase price.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

Discontinued Operations

Discontinued operations for the nine months ended September 30, 2014 included the results of operations for a marketing business that had been recently acquired by ETP and was sold effective April 1, 2014, as well as a $39 million gain on the sale. The disposed subsidiary’s results of operations were not material during any periods in 2013; therefore, the disposed subsidiary’s results were not reclassified to discontinued operations in the prior period.

Discontinued operations for the three and nine months ended September 30, 2013 included the results of Southern Union’s distribution operations.

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3. ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The following investments in unconsolidated affiliates are reflected in our consolidated financial statements using the equity method:

• AmeriGas. During the nine months ended September 30, 2014, ETP sold a total of approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and for general partnership purposes. Subsequent to the sales, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.

• Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.

• FEP. ETP owns a 50% interest in the FEP, which owns a natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company, LLC in Panola County, Mississippi.

• HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the Regency Intrastate Gas System, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through an intrastate pipeline system.

• MEP. Regency owns a 50% interest in MEP, which owns natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.

The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenue	$	919	$	883	$	3,703	$	3,324
Operating income	206		196		881		839
Net income	82		64		505		460

In addition to the equity method investments described above, our subsidiaries have other equity method investments, which are not significant to our consolidated financial statements.

In May 2014, Sunoco Logistics entered into a joint agreement to form Bayview Refining Company, LLC (“Bayview”). Bayview will construct and operate a facility that will process crude oil into intermediate petroleum products. Sunoco Logistics will fund construction of the facility through contributions proportionate to its 49% economic and voting interests, with the remaining portion funded by the joint owner through a promissory note entered into with Sunoco Logistics. Through September 30, 2014, the joint owners have made contributions totaling $21 million. The facility is expected to commence operations in the second half of 2015. Bayview is a variable interest entity of which Sunoco Logistics is not the primary beneficiary. As a result, Sunoco Logistics’ interest in Bayview is reflected as an equity method investment.

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4. 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.

Non-cash investing and financing activities were as follows:

	Nine Months Ended September 30,
	2014		2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	399	$	260
Net gains (losses) from subsidiary common unit transactions	$	702	$	(410	)
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions	$	4,281	$	—
Subsidiary issuances of common units in connection with Susser Merger	$	1,312	$	—
Long-term debt assumed in PVR Acquisition	$	1,887	$	—
Long-term debt exchanged in Eagle Rock Midstream Acquisition	$	499	$	—

5. INVENTORIES:

Inventories consisted of the following:

	September 30, 2014		December 31, 2013
Natural gas and NGLs	$	404	$	523
Crude oil	459		488
Refined products	597		597
Appliances, parts and fittings and other	320		199
Total inventories	$	1,780	$	1,807

ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

6. FAIR VALUE MEASUREMENTS:

We have commodity derivatives, interest rate derivatives and embedded derivatives in the Regency 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 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, and we discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency 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,

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common unit price, dividend yield, and expected value, and are considered Level 3. During the nine months endedSeptember 30, 2014, no transfers were made between any levels within the fair value hierarchy.

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 of our consolidated debt obligations as of September 30, 2014 and December 31, 2013 was $31.23 billion and $23.97 billion, respectively. As of September 30, 2014 and December 31, 2013, the aggregate carrying amount of our consolidated debt obligations was $29.85 billion and $23.20 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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 September 30, 2014 and December 31, 2013 based on inputs used to derive their fair values:

	Fair Value Measurements at September 30, 2014
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	3		$	—		$	3		$	—
Commodity derivatives:
Condensate — Forward Swaps	4			—			4			—
Natural Gas:
Basis Swaps IFERC/NYMEX	6			6			—			—
Swing Swaps IFERC	6			1			5			—
Fixed Swaps/Futures	75			69			6			—
Forward Physical Swaps	1			—			1			—
Natural Gas Liquids — Forwards/Swaps	16			13			3			—
Power:
Forwards	2			—			2			—
Futures	1			1			—			—
Refined Products — Futures	19			19			—			—
Total commodity derivatives	130			109			21			—
Total assets	$	133		$	109		$	24		$	—
Liabilities:
Interest rate derivatives	$	(86	)	$	—		$	(86	)	$	—
Embedded derivatives in the Regency Preferred Units	(30		)	—			—			(30		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(8		)	(8		)	—			—
Swing Swaps IFERC	(5		)	(1		)	(4		)	—
Fixed Swaps/Futures	(75		)	(73		)	(2		)	—
Forward Physical Swaps	(1		)	—			(1		)	—
Natural Gas Liquids — Forwards/Swaps	(19		)	(18		)	(1		)	—
Power:
Forwards	(2		)	—			(2		)	—
Futures	(2		)	(2		)	—			—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(118		)	(107		)	(11		)	—
Total liabilities	$	(234	)	$	(107	)	$	(97	)	$	(30	)

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	Fair Value Measurements at December 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	47		$	—		$	47		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	8			1			7			—
Fixed Swaps/Futures	203			201			2			—
NGLs — Swaps	7			5			2			—
Power — Forwards	3			—			3			—
Refined Products — Futures	5			5			—			—
Total commodity derivatives	231			217			14			—
Total Assets	$	278		$	217		$	61		$	—
Liabilities:
Interest rate derivatives	$	(95	)	$	—		$	(95	)	$	—
Embedded derivatives in the Regency Preferred Units	(19		)	—			—			(19		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)	(4		)	—			—
Swing Swaps IFERC	(6		)	—			(6		)	—
Fixed Swaps/Futures	(206		)	(201		)	(5		)	—
Forward Physical Contracts	(1		)	—			(1		)	—
NGLs — Swaps	(9		)	(5		)	(4		)	—
Power — Forwards	(1		)	—			(1		)	—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(233		)	(215		)	(18		)	—
Total Liabilities	$	(347	)	$	(215	)	$	(113	)	$	(19	)

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 nine months endedSeptember 30, 2014.

Balance, December 31, 2013	$	(19	)
Net unrealized loss included in other income (expense)	(11		)
Balance, September 30, 2014	$	(30	)

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7. NET INCOME PER LIMITED PARTNER UNIT:

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
Income from continuing operations	$	470		$	343	$	1,352		$	972
Less: Income from continuing operations attributable to noncontrolling interest	282			195		839			623
Income from continuing operations, net of noncontrolling interest	188			148		513			349
Less: General Partner’s interest in income from continuing operations	—			1		1			1
Less: Class D Unitholder’s interest in income from continuing operations	—			—		1			—
Income from continuing operations available to Limited Partners	$	188		$	147	$	511		$	348
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	538.8			561.4		546.6			560.8
Basic income from continuing operations per Limited Partner unit	$	0.35		$	0.26	$	0.94		$	0.62
Basic income from discontinued operations per Limited Partner unit	$	—		$	0.01	$	0.01		$	0.03
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	188		$	147	$	511		$	348
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1		)	—		(2		)	(1		)
Diluted income from continuing operations available to Limited Partners	$	187		$	147	$	509		$	347
Weighted average limited partner units	538.8			561.4		546.6			560.8
Dilutive effect of unconverted unit awards	1.1			—		1.0			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	539.9			561.4		547.6			560.8
Diluted income from continuing operations per Limited Partner unit	$	0.35		$	0.26	$	0.93		$	0.62
Diluted income from discontinued operations per Limited Partner unit	$	—		$	0.01	$	0.01		$	0.03

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8. DEBT OBLIGATIONS:

Our outstanding consolidated indebtedness was as follows:

	September 30, 2014		December 31, 2013
Parent Company Indebtedness:
ETE Senior Notes due October 15, 2020	$	1,187	$	1,187
ETE Senior Notes due January 15, 2024	1,150		450
ETE Senior Secured Term Loan due December 2, 2019	1,400		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	800		171
Subsidiary Indebtedness:
ETP Senior Notes	10,890		11,182
Regency Senior Notes	4,899		2,800
PVR Senior Notes	789		—
Transwestern Senior Notes	870		870
Panhandle Senior Notes	1,085		1,085
Sunoco Senior Notes	965		965
Sunoco Logistics Senior Notes	2,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	800		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	689		510
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	35		35
Sunoco Logistics $1.5 billion Revolving Credit Facility due November 19, 2018	525		200
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019	270		—
Other Long-Term Debt	220		228
Unamortized premiums, net of discounts and fair value adjustments	304		301
Total	29,853		23,199
Less: Current maturities of long-term debt	1,345		637
Long-term debt and notes payable, less current maturities	$	28,508	$	22,562

Parent Company Indebtedness

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

ETE Term Loan Facility

In April 2014, the Parent Company amended its Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”) to increase the aggregate principal amount to $1.4 billion. The Parent Company used the proceeds from this $400 million increase to repay borrowings under its revolving credit facility and for general partnership purposes. No other significant changes were made to the terms of the ETE Term Credit Agreement, including maturity date and interest rate.

Revolving Credit Facility

In May 2014, the Parent Company amended its revolving credit facility to increase the capacity to $1.2 billion. As of September 30, 2014, there were $800 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $400 million.

Senior Notes

In May 2014, the Parent Company issued an additional $700 million in principal amount of its 5.875% senior notes due 2024 in a private placement and used the net proceeds to repay amounts outstanding under its revolving credit facility and for general partnership purposes.

The Parent Company currently has outstanding an aggregate of $1.19 billion in principal amount of 7.5% senior notes due 2020 and $1.15 billion in principal amount of 5.875% senior notes due 2024.

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Sunoco Logistics Senior Notes

In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044. The net proceeds from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facility and for general partnership purposes.

Regency Senior Notes

In February 2014, Regency issued $900 million aggregate principal amount of 5.875% senior notes due March 1, 2022.

In March 2014, as part of the PVR Acquisition, Regency assumed the outstanding senior notes of PVR with an aggregate notional amount of $1.2 billion. The PVR senior notes consisted of $300 million principal amount of 8.25% senior notes due April 15, 2018, $400 million principal amount of 6.5% senior notes due May 15, 2021, and $473 million principal amount of 8.375% senior notes due June 1, 2020. In April 2014, Regency redeemed all of the $300 million principal amount of 8.25% senior notes due April 15, 2018 for $313 million in cash. In July 2014, Regency redeemed $83 million of the $473 million principal amount of 8.375% senior notes due June 1, 2020 for $91 million, including $8 million of accrued interest and redemption premium.

In July 2014, Regency exchanged $499 million aggregate principal amount of 8.375% senior notes due 2019 of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% Senior Notes due 2019 issued by Regency and its wholly-owned subsidiary.

In July 2014, Regency issued $700 million aggregate principal amount of 5.0% senior notes that mature on October 1, 2022.

In October 2014, Regency issued a notice of redemption to the holders of the $600 million6.875% senior notes due December 1, 2018, with a redemption date of December 2, 2014 for a total price of 103.438%.

Subsidiary Credit Facilities

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2017. 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 ETP’s current and future unsecured debt. As of September 30, 2014, the ETP Credit Facility had $800 million of outstanding borrowings.

Regency Credit Facility

In February 2014, Regency entered into an amendment to the Regency Credit Facility to increase the borrowing capacity of the Regency Credit Facility to $1.5 billion with a $500 million uncommitted incremental facility and extended the maturity date to May 21, 2018. In September 2014, Regency entered into an amendment to, among other things, increase the letter of credit sublimit from $50 million to $100 million and update various swap agreement provisions to conform to current market standards. As of September 30, 2014, the Regency Credit Facility had a balance outstanding of $689 million in outstanding borrowings and approximately $25 million in letters of credit.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $1.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $2.25 billion under certain conditions. As of September 30, 2014, the Sunoco Logistics Credit Facility had $525 million of outstanding borrowings.

Sunoco LP Credit Facility

On September 25, 2014, Sunoco LP entered into a $1.25 billion revolving credit agreement (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 September 30, 2014, the Sunoco LP Credit Facility had $270 million of outstanding borrowings.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2014.

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9. REDEEMABLE NONCONTROLLING INTERESTS:

The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet as of September 30, 2014.

10. EQUITY:

ETE Common Unit Activity

The change in ETE Common Units during the nine months ended September 30, 2014 was as follows:

	Number of Units
Outstanding at December 31, 2013	559.9
Repurchase of units under buyback program	(21.1	)
Outstanding at September 30, 2014	538.8

From January through May, ETE repurchased approximately $1 billion of ETE common units, completing its buyback program.

Sales of Common Units by Subsidiaries

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

As a result of ETP’s and Regency’s issuances of common units during the nine months endedSeptember 30, 2014, we recognized increases in partners’ capital of $702 million.

Sales of Common Units by ETP

During thenine months ended September 30,2014, ETP received proceeds of$1.03 billion, net of commissions of$11 million, from the issuance of units pursuant to equity distribution agreements, which proceeds were used for general partnership purposes. As ofSeptember 30, 2014, approximately$109 million of ETP Common Units remained available to be issued under an equity distribution agreement, and all of the remaining capacity was utilized in October 2014.

During the nine months ended September 30,2014, distributions of $100 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 1.9 million ETP Common Units. As of September 30, 2014, a total of 0.2 million ETP Common Units remain available to be issued under the existing registration statement.

In October 2014, ETP filed a new registration statement with the SEC covering the issuance of up to an additional 8 million ETP Common Units under the Distribution Reinvestment Plan.

Sales of Common Units by Regency

For the nine months ended September 30,2014, Regency received proceeds of $162 million, net of commissions of approximately $2 million, from units issued pursuant to its equity distribution agreements, which proceeds were used for general partnership purposes. As of September 30, 2014, approximately $272 million remained available to be issued under the agreement.

Regency issued 4.0 million, 140.4 million and 8.2 million Regency Common Units in connection with the Hoover, PVR and Eagle Rock Midstream acquisitions, respectively.

In June 2014, Regency sold 14.4 million Regency Common Units to a wholly-owned subsidiary of ETE for approximately $400 million. In July 2014, Regency sold an additional 16.5 million Regency Common Units to a wholly-owned subsidiary of ETE in connection with the Eagle Rock Midstream Acquisition for approximately $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition.

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Sales of Common Units by Sunoco Logistics

In May 2014, Sunoco Logistics entered into an equity distribution agreement pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $250 million. During the nine months ended September 30,2014, Sunoco Logistics received proceeds of $231 million, net of commissions of $2 million, from the issuance of units pursuant to an equity distribution agreement, which were used for general partnership purposes. All remaining units authorized under this distribution agreement were issued during October 2014.

In September 2014, Sunoco Logistics filed a registration statement which will allow it to issue up to an additional $1.0 billion of common units directly to the public under its equity distribution agreement.

Additionally, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.5 billion Sunoco Logistics Credit Facility and for general partnership purposes.

Sales of Common Units by Sunoco LP

In October 2014, Sunoco LP issued 8.0 million common units in an underwritten public offering. Net proceeds of $359 million from the offering were used to repay amounts outstanding under the $1.25 billion Sunoco LP Credit Facility and for general partnership purposes.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 19, 2014	$	0.34625
March 31, 2014	May 5, 2014	May 19, 2014	0.35875
June 30, 2014	August 4, 2014	August 19, 2014	0.38000
September 30, 2014	November 3, 2014	November 19, 2014	0.41500

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.9200
March 31, 2014	May 5, 2014	May 15, 2014	0.9350
June 30, 2014	August 4, 2014	August 14, 2014	0.9550
September 30, 2014	November 3, 2014	November 14, 2014	0.9750

In connection with previous transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods, and ETP has agreed to make incremental distributions on the Class H Units in future periods. The net impact of these adjustments will result in a reduction of $88 million in the distributions to be paid from ETP to ETE for the nine months endedSeptember 30, 2014. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods:

	Total Year
2014 (remainder)	$	35
2015	86
2016	107
2017	85
2018	80
2019	70

The amounts reflected above include the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE by ETP over the first forty fiscal quarters commencing immediately after the consummation of

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the Susser Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interest and the incentive distribution rights between ETE and ETP.

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.4750
March 31, 2014	May 8, 2014	May 15, 2014	0.4800
June 30, 2014	August 7, 2014	August 14, 2014	0.4900
September 30, 2014	November 7, 2014	November 14, 2014	0.5025

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 10, 2014	February 14, 2014	$	0.3312
March 31, 2014	May 9, 2014	May 15, 2014	0.3475
June 30, 2014	August 8, 2014	August 14, 2014	0.3650
September 30, 2014	November 7, 2014	November 14, 2014	0.3825

Sunoco Logistics Unit Split

On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014:

Quarter Ended	Record Date	Payment Date	Rate
September 30, 2014	November 18, 2014	November 28, 2014	$	0.5457

Accumulated Other Comprehensive Income

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

	September 30, 2014			December 31, 2013
Available-for-sale securities	$	3		$	2
Foreign currency translation adjustment	(4		)	(1		)
Net loss on commodity related hedges	(1		)	(4		)
Actuarial gain related to pensions and other postretirement benefits	54			56
Investments in unconsolidated affiliates, net	2			8
Subtotal	54			61
Amounts attributable to noncontrolling interest	(49		)	(52		)
Total AOCI, net of tax	$	5		$	9

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11. INCOME TAXES:

Income tax expense from continuing operations for the nine months ended September 30, 2014 included the impact of the Lake Charles LNG Transaction, which was treated as a sale for tax purposes, resulting in $87 million of incremental income tax expense.

The acquisition of Susser by ETP (see Note 2) on August 29, 2014 did not have a material impact on income tax expense or the effective rate for the third quarter of 2014 due to the timing of the acquisition. However, the acquisition of Susser is expected to increase the effective rate for the full year of 2014. Additionally, deferred tax liabilities increased by approximately $457 million as a result of the acquisition.

12. RETIREMENT BENEFITS:

The following table sets forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans:

	Three Months Ended September 30,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—		$	—		$	—		$	(1	)
Interest cost	8			1			10			2
Expected return on plan assets	(10		)	(2		)	(15		)	(3		)
Prior service cost amortization	—			—			—			1
Actuarial loss amortization	—			—			1			—
Settlement credits	(1		)	—			—			—
	(3		)	(1		)	(4		)	(1		)
Regulatory adjustment	—			—			1			—
Net periodic benefit cost	$	(3	)	$	(1	)	$	(3	)	$	(1	)

	Nine Months Ended September 30,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	1		$	—		$	5		$	—
Interest cost	23			4			28			5
Expected return on plan assets	(30		)	(6		)	(45		)	(7		)
Prior service cost amortization	—			—			—			1
Actuarial (gain) loss amortization	(1		)	—			2			—
Settlement credits	(3		)	—			(2		)	—
	(10		)	(2		)	(12		)	(1		)
Regulatory adjustment	—			—			5			—
Net periodic benefit cost	$	(10	)	$	(2	)	$	(7	)	$	(1	)

Panhandle has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset

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or liability and reflected in expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

Panhandle no longer has pension plans after the sale of the assets of Missouri Gas Energy and New England Gas Company in 2013.

13. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus

Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.

On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.

FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.

Contingent Residual Support Agreement — AmeriGas

In connection with the closing of the contribution of ETP’s propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of senior notes issued by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases.

PEPL Holdings Guarantee of Collection

In connection with the SUGS Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023(the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.

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.

Transwestern Rate Case

On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to a 2011 settlement agreement with its shippers.  Transwestern expects the FERC to set a procedural schedule with a hearing scheduled in late 2015 for this case.

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FGT Rate Case

On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. FGT expects the FERC to set a procedural schedule with a hearing scheduled in late 2015 for this case.

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 2056.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Rental expense(1)	$	31		$	33		$	90		$	98
Less: Sublease rental income	(9		)	(6		)	(27		)	(16		)
Rental expense, net	$	22		$	27		$	63		$	82

⁽¹⁾  Includes contingent rentals totaling $8 million for the three months ended September 30,2014 and 2013, and $17 million and $18 million for the nine months ended September 30,2014 and 2013, 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.

MTBE Litigation

Sunoco, 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 are asserting primarily 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 are seeking to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As of September 30, 2014, Sunoco is a defendant in nine cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of 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. Six of these cases are venued in a multidistrict litigation (“MDL”) proceeding in a New York federal court. The most recently filed Puerto Rico action is expected to be transferred to the MDL. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.

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Fact discovery has concluded with respect to an initial set of fewer than 20 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco in these matters. 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.

Litigation Relating to the PVR Merger

Five putative class action lawsuits challenging the merger have been filed and are currently pending. All of the cases name PVR, PVR GP and the current directors of PVR GP, as well as Regency and the General Partner of Regency (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of their fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly caused by the defendants to these actions, and, (vi) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. (Case No. 9015-VCL) in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606) and Saul Srour v. PVR Partners, L.P., et al. (Case No. 2013-011015), each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-06829-HB); and Mark Hinnau v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-07496-HB), pending in the United States District Court for the Eastern District of Pennsylvania.

On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, which occurred on March 21, 2014, completion of certain confirmatory discovery, class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.

The settlement will not affect any provisions of the merger agreement or the form or amount of consideration received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.

Utility Line Services, Inc. v. PVR Marcellus Gas Gathering LLC

On May 22, 2012, Plaintiff and Counterclaim Defendant, Utility Line Services, Inc. (“ULS”) filed suit against PVR Marcellus Gas Gathering, LLC now known as Regency Marcellus Gas Gathering LLC (“Regency Marcellus”) relating to a dispute involving payment under a construction contract (the “Construction Contract”) entered into in October 2010 for Regency Marcellus’ multi-phase pipeline construction project in Lycoming County, PA (the “Project”). Under the terms of the Construction Contract, Regency Marcellus believed ULS was obligated to design, permit and build Phases I and II of Regency Marcellus’ 30-inch pipeline and to design additional phases of the project.Due to ULS’ deficiencies and delays throughout the project, as well as extensive overbilling for its services, Regency Marcellus allowed the Construction Contractto terminate in accordance with its terms in December 2011 and refused to pay ULS’ outstanding invoices for the Project. ULS then filed suit alleging: Regency Marcellus’ refusal to pay certain invoices totaling approximately $17 million; penalties pursuant to the Pennsylvania Contractor and Subcontractor Payment Act, 73 P.S. § 501, et seq. (“CASPA”), Regency Marcellus’ alleged wrongful withholding of payments owed to ULS; and breach of contract in connection with Regency Marcellus’ alleged wrongful termination of ULS in December 2011.  ULS alleged damages, inclusive of CASPA penalties, are in excess of $30 million. Regency Marcellus alleged counterclaims against ULS for breach of the parties’ contract for engineering and construction services; restitution for Regency Marcellus’ overpayments to ULS because of ULS’ improper billing practices; attorneys’ fees resulting from ULS’ meritless claim under CASPA; and professional malpractice against ULS for negligent performance of various engineering services on the Project. Regency Marcellus’ alleged damages exceed $21 million.

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Trial commenced on March 24, 2014 and on April 17, 2014, the jury found in favor of ULS and assessed damages against Regency Marcellus of approximately $24 million plus interest and penalties. In June 2014, ULS and Regency Marcellus reached a settlement in this matter, the terms of which are confidential. The settlement will not have a material adverse effect on Regency’s business or financial position.

Litigation Related to the Eagle Rock Midstream Acquisition

Three putative class action lawsuits challenging Regency’s acquisition of the Eagle Rock midstream assets are currently pending in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as Regency and a subsidiary as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction, claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. Regency and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of September 30, 2014 and December 31, 2013, accruals of approximately $42 million and $46 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 September 30, 2014 or December 31, 2013 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 $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, Southern Union’s 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.

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Environmental Matters

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

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

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

Environmental Remediation

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

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

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

• Currently operating Sunoco retail sites.

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

• Sunoco 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 September 30, 2014, Sunoco had been named as a PRP at approximately 49 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law.  Sunoco is usually one of a number of companies identified as a PRP at a site.  Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’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.

	September 30, 2014		December 31, 2013
Current	$	73	$	47
Non-current	321		356
Total environmental liabilities	$	394	$	403

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

During the three months ended September 30, 2014 and 2013, the Partnership recorded $10 million and $9 million, respectively, of expenditures related to environmental cleanup programs. During the nine months endedSeptember 30, 2014 and 2013, the Partnership recorded $27 million of expenditures related to environmental cleanup programs.

On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines.  The rule became effective on August 29, 2011.  The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future.  At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.

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.

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.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the New Mexico Environmental Department (“NMED”) and the Texas Commission on Environmental Quality (“TCEQ”). The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three SUGS recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.

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Compliance Orders from the New Mexico Environmental Department. SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until October 2014 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

14. PRICE RISK MANAGEMENT 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. Following is a description of price risk management activities by operating entity.

ETP

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges 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. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of ETP’s derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s interstate transportation and storage segment. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in ETP’s midstream segment whereby ETP’s 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 NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP may use derivatives in ETP’s NGL transportation and services segment to manage ETP’s storage facilities and the purchase and sale of purity NGLs.

Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.

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ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used 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. The derivatives used in ETP’s retail marketing operations represent economic hedges; however, ETP has elected not to designate any of the hedges in these operations. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.

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

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The following table details ETP’s outstanding commodity-related derivatives:

	September 30, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	920,000		2014-2015	9,457,500		2014-2019
Basis Swaps IFERC/NYMEX (1)	2,882,500		2014-2015	(487,500	)	2014-2017
Options – Puts	5,000,000		2015	—		—
Swing Swaps	—		—	1,937,500		2014-2016
Power (Megawatt):
Forwards	343,775		2014	351,050		2014
Futures	(57,744	)	2014	(772,476	)	2014
Options — Puts	(54,400	)	2014	(52,800	)	2014
Options — Calls	54,400		2014	103,200		2014
Crude (Bbls) — Futures	(81,000	)	2014	103,000		2014
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(7,182,500	)	2014-2015	570,000		2014
Swing Swaps IFERC	17,790,000		2014	(9,690,000	)	2014-2016
Fixed Swaps/Futures	(8,067,500	)	2014-2019	(8,195,000	)	2014-2015
Forward Physical Contracts	(9,325,164	)	2014-2015	5,668,559		2014-2015
Natural Gas Liquid (Bbls) — Forwards/Swaps	(1,602,800	)	2014-2015	(1,133,600	)	2014
Refined Products (Bbls) — Futures	(243,000	)	2014-2015	(280,000	)	2014
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(24,197,500	)	2015	(7,352,500	)	2014
Fixed Swaps/Futures	(24,197,500	)	2015	(50,530,000	)	2014
Hedged Item — Inventory	24,197,500		2015	50,530,000		2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(460,000	)	2014	(1,825,000	)	2014
Fixed Swaps/Futures	(3,220,000	)	2014	(12,775,000	)	2014
Natural Gas Liquid (Bbls) — Forwards/Swaps	(255,000	)	2014	(780,000	)	2014
Crude (Bbls) — Futures	—		—	(30,000	)	2014

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

We expect gains of less than $1 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Regency

Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability

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and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.

Commodity Derivative Instruments - Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency’s activities are governed by its risk policy. As part of its natural gas marketing and trading activities, Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales. Through Regency’s natural gas marketing activity, Regency will have credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty.

The following table details Regency’s outstanding commodity-related derivatives:

	September 30, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(13,289,000	)	2014-2015	(24,455,000	)	2014-2015
Propane (Gallons) — Forwards/Swaps	(44,562,000	)	2014-2015	(52,122,000	)	2014-2015
NGLs (Barrels) — Forwards/Swaps	(439,000	)	2014-2015	(438,000	)	2014
WTI Crude Oil (Barrels) — Forwards/Swaps	(1,715,000	)	2014-2016	(521,000	)	2014

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
Entity	Term	Type(1)	September 30, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	—	$	400
ETP	July 2015(2)	Forward-starting to pay a fixed rate of 3.38% and receive a floating rate	200		—
ETP	July 2016(3)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	200		—
ETP	July 2017(4)	Forward-starting to pay a fixed rate of 4.18% and receive a floating rate	200		—
ETP	July 2018(4)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		—
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	—		600
ETP	June 2021	Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%	—		400
ETP	February 2023	Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%	200		400
Panhandle	November 2021	Pay a fixed rate of 3.82% and receive a floating rate	125		275

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

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

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

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

ETP’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, utilities and midstream companies. ETP’s overall exposure may be affected positively or negatively by macroeconomic 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

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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.

Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of September 30, 2014 would be $10 million, which would be reduced by $2 million, due to the netting features. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations.

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

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014			December 31, 2013
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	2	$	3	$	(3	)	$	(18	)
	2		3		(3		)	(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	114	$	227	$	(110	)	$	(209	)
Commodity derivatives	25		43		(16		)	(48		)
Interest rate derivatives	3		47		(86		)	(95		)
Embedded derivatives in Regency Preferred Units	—		—		(30		)	(19		)
	142		317		(242		)	(371		)
Total derivatives	$	144	$	320	$	(245	)	$	(389	)

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

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2014			December 31, 2013			September 30, 2014			December 31, 2013
Derivatives in offsetting agreements:
OTC contracts	Price risk management asset (liability)	$	12		$	42		$	(12	)	$	(38	)
Broker cleared derivative contracts	Other current assets	130			264			(152		)	(318		)
		142			306			(164		)	(356		)
Offsetting agreements:
Counterparty netting	Price risk management asset (liability)	(9		)	(36		)	9			36
Payments on margin deposit	Other current assets	(5		)	(1		)	30			55
		(14		)	(37		)	39			91
Net derivatives with offsetting agreements		128			269			(125		)	(265		)
Derivatives without offsetting agreements		16			51			(120		)	(124		)
Total derivatives		$	144		$	320		$	(245	)	$	(389	)

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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 September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	3	$	(4	)	$	(3	)	$	4
Total	$	3	$	(4	)	$	(3	)	$	4

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	—	$	3	$	(6	)	$	5
Total		$	—	$	3	$	(6	)	$	5

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014			2013
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	1	$	—	$	(5	)	$	4
Total		$	1	$	—	$	(5	)	$	4

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	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(4	)	$	(11	)	$	(2	)	$	(12	)
Commodity derivatives – Non-trading	Cost of products sold	52			(34		)	9			(20		)
Commodity derivatives – Non-trading	Deferred gas purchases	—			—			—			(3		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(25		)	3			(73		)	55
Embedded derivatives	Other income	(1		)	24			(11		)	2
Total		$	22		$	(18	)	$	(77	)	$	22

15. RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various 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 $261 million and $951 million during the three and nine months ended September 30, 2014, respectively, and $387 million and $1.08 billion during the three and nine months ended September 30, 2013, respectively.

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16. OTHER INFORMATION:

The tables below present additional detail for certain balance sheet captions.

Other Current Assets

Other current assets consisted of the following:

	September 30, 2014		December 31, 2013
Deposits paid to vendors	$	46	$	49
Prepaid expenses and other	261		263
Total other current assets	$	307	$	312

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	September 30, 2014		December 31, 2013
Interest payable	$	410	$	357
Customer advances and deposits	95		142
Accrued capital expenditures	398		260
Accrued wages and benefits	204		173
Taxes payable other than income taxes	343		211
Income taxes payable	127		4
Deferred income taxes	132		119
Other	399		412
Total accrued and other current liabilities	$	2,108	$	1,678

39

17. REPORTABLE SEGMENTS:

As a result of the Lake Charles LNG Transaction in 2014, our reportable segments were re-evaluated and currently reflect the following reportable segments:

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

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

• 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.

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, loss on extinguishment 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.

Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.

Eliminations in the tables below include the following:

• ETP’s Segment Adjusted EBITDA reflected 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA included its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star were included in eliminations.

• ETP’s Segment Adjusted EBITDA reflected the results of SUGS from March 26, 2012 to April 30, 2013. Since the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also included the results of SUGS from March 26, 2012 to April 30, 2013.

• ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the three and nine months ended September 30, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013.

40

The following tables present financial information by segment:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Segment Adjusted EBITDA:
Investment in ETP	$	1,172		$	942		$	3,547		$	2,967
Investment in Regency	344			172			856			446
Investment in Lake Charles LNG	51			47			146			139
Corporate and Other	(18		)	(9		)	(73		)	(38		)
Adjustments and Eliminations	(78		)	(103		)	(190		)	(250		)
Total	1,471			1,049			4,286			3,264
Depreciation, depletion and amortization	(425		)	(332		)	(1,248		)	(962		)
Interest expense, net of interest capitalized	(356		)	(298		)	(1,015		)	(913		)
Gain on sale of AmeriGas common units	14			87			177			87
Gains (losses) on interest rate derivatives	(25		)	3			(73		)	55
Non-cash unit-based compensation expense	(20		)	(16		)	(60		)	(43		)
Unrealized gains (losses) on commodity risk management activities	32			22			(11		)	45
Gains (losses) on extinguishment of debt	2			—			2			(7		)
LIFO valuation adjustments	(51		)	6			(17		)	22
Equity in earnings of unconsolidated affiliates	84			38			265			182
Adjusted EBITDA related to unconsolidated affiliates	(183		)	(165		)	(583		)	(553		)
Adjusted EBITDA related to discontinued operations	—			(12		)	(27		)	(75		)
Other, net	(17		)	10			(73		)	6
Income from continuing operations before income tax expense	$	526		$	392		$	1,623		$	1,108

	September 30, 2014			December 31, 2013
Total assets:
Investment in ETP	$	48,571		$	43,702
Investment in Regency	17,180			8,782
Investment in Lake Charles LNG	1,170			1,338
Corporate and Other	804			720
Adjustments and Eliminations	(3,044		)	(4,212		)
Total	$	64,681		$	50,330

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues:
Investment in ETP:
Revenues from external customers	$	13,573		$	11,848		$	38,778		$	34,214
Intersegment revenues	45			54			101			93
	13,618			11,902			38,879			34,307
Investment in Regency:
Revenues from external customers	1,381			633			3,282			1,796
Intersegment revenues	102			32			242			48
	1,483			665			3,524			1,844
Investment in Lake Charles LNG:
Revenues from external customers	55			55			162			162
Adjustments and Eliminations	(169		)	(136		)	(355		)	(585		)
Total revenues	$	14,987		$	12,486		$	42,210		$	35,728

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

Investment in ETP

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Intrastate Transportation and Storage	$	559	$	502	$	2,075	$	1,705
Interstate Transportation and Storage	254		296		794		973
Midstream	311		334		915		973
Liquids Transportation and Services	1,165		537		2,844		1,303
Investment in Sunoco Logistics	4,862		4,502		14,080		12,215
Retail Marketing	5,985		5,297		16,561		15,805
All Other	482		434		1,610		1,333
Total revenues	13,618		11,902		38,879		34,307
Less: Intersegment revenues	45		54		101		93
Revenues from external customers	$	13,573	$	11,848	$	38,778	$	34,214

Investment in Regency

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Gathering and Processing	$	1,387	$	603	$	3,254	$	1,671
Contract Services	76		58		217		159
Natural Resources	18		—		40		—
Corporate and Other	2		4		13		14
Total revenues	1,483		665		3,524		1,844
Less: Intersegment revenues	102		32		242		48
Revenues from external customers	$	1,381	$	633	$	3,282	$	1,796

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Investment in Lake Charles LNG

Lake Charles LNG’s revenues of $55 million and $162 million for the three and nine months ended September 30, 2014, respectively, and $55 million and $162 million for the three and nine months ended September 30, 2013, respectively, were related to LNG terminalling.

18. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS

(unaudited)

	September 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9		$	8
Accounts receivable from related companies	13			5
Other current assets	1			—
Total current assets	23			13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,303			3,841
INTANGIBLE ASSETS, net	11			14
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	49			41
Total assets	$	5,395		$	3,918
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related companies	$	77		$	11
Interest payable	63			24
Accrued and other current liabilities	3			3
Total current liabilities	143			38
LONG-TERM DEBT, less current maturities	4,540			2,801
OTHER NON-CURRENT LIABILITIES	3			1
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	687			1,066
Class D Units	18			6
Accumulated other comprehensive income	5			9
Total partners’ capital	709			1,078
Total liabilities and partners’ capital	$	5,395		$	3,918

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STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(20	)	$	(11	)	$	(83	)	$	(40	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(57		)	(47		)	(147		)	(164		)
Gains on interest rate derivatives	—			3			—			9
Equity in earnings of unconsolidated affiliates	269			207			756			573
Other, net	(2		)	(1		)	(4		)	(11		)
INCOME BEFORE INCOME TAXES	190			151			522			367
Income tax expense (benefit)	2			—			2			(1		)
NET INCOME	188			151			520			368
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1			1			1
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	—			—			1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	188		$	150		$	518		$	367

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STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended September 30,
	2014			2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	704		$	650
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds received in acquisitions and other transactions, net	—			1,332
Contributions to unconsolidated affiliate	(30		)	(8		)
Purchase of additional interest in Regency	(800		)	—
Payments received on note receivable from affiliate	—			166
Net cash used in investing activities	(830		)	1,490
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,820			440
Principal payments on debt	(1,082		)	(1,603		)
Distributions to partners	(596		)	(544		)
Redemption of Preferred Units	—			(340		)
Units repurchased under buyback program	(1,000		)	—
Debt issuance costs	(15		)	(2		)
Net cash used in financing activities	127			(2,049		)
INCREASE IN CASH AND CASH EQUIVALENTS	1			91
CASH AND CASH EQUIVALENTS, beginning of period	8			9
CASH AND CASH EQUIVALENTS, end of period	$	9		$	100

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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, 2013 filed with the SEC on February 27, 2014. 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, 2013.

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, Regency and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

Our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names in September 2014 and October 2014, respectively, to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP, respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.

OVERVIEW

We directly and indirectly own equity interests in entities that are engaged in diversified energy-related services. At September 30, 2014, our interests in ETP and Regency consisted of 100% of the respective general partner interests and IDRs, as well as the following:

	ETP	Regency
Units held by wholly-owned subsidiaries:
Common units	30.8	57.2
ETP Class H units	50.2	—
Units held by less than wholly-owned subsidiaries:
Common units	—	31.4
Regency Class F units	—	6.3

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 Regency and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and, at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.

As a result of the Lake Charles LNG Transaction in 2014, our reportable segments were re-evaluated and currently reflect the following reportable segments:

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

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

• 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.

Each of the respective general partners of ETP and Regency has separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners.

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RECENT DEVELOPMENTS

ETP’s Gathering and Processing Construction Projects

On November 5, 2014, ETP announced its plans to construct two new 200 million cubic feet per day cryogenic gas processing plants and associated gathering systems in the Eagle Ford and Eaglebine production areas.  ETP expects to have the first plant online by June 2015 and the second plant by the fourth quarter of 2015.

Lone Star Fractionator

On November 5, 2014, ETP and Regency announced that Lone Star will construct a third natural gas liquids fractionator at its facility in Mont Belvieu, Texas, which will bring Lone Star’s total fractionation capacity at Mont Belvieu to 300,000 Bbls/d. Lone Star’s third fractionator is scheduled to be operational by December 2015.

Phillips 66 Joint Venture

In October 2014, ETE, ETP and Phillips 66 announced that they have formed two joint ventures to develop the previously announced Dakota Access Pipeline (“DAPL”) and Energy Transfer Crude Oil Pipeline (“ETCOP”) projects. ETP and ETE will hold an aggregate interest of 75% in each joint venture and will operate both pipeline systems. Phillips 66 owns the remaining 25% interests and will fund its proportionate share of the construction costs. The DAPL and ETCOP projects are expected to begin commercial operations in the fourth quarter of 2016.

ET Rover

In October 2014, ETP announced it has secured additional long-term binding shipper agreements on its Rover natural gas pipeline project to connect Marcellus and Utica share supplies to markets in the Midwest, Great Lakes and Gulf Coast regions of the United States and Canada. As a result of the additional agreements, the pipeline is fully subscribed with 15 and 20 year fee-based contracts to transport 3.25 billion cubic feet per day of capacity.

MACS to Sunoco LP

On October 1, 2014, Sunoco LP acquired MACS from ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with net proceeds of $359 million from a public offering of 8 million Sunoco LP common units.

Aloha Petroleum Acquisition

On September 25, 2014, Sunoco LP entered into a definitive agreement to acquire Honolulu, Hawaii-based Aloha Petroleum, Ltd (“Aloha Petroleum”). Aloha Petroleum is an independent gasoline marketer and convenience store operator in Hawaii, with an extensive wholesale fuel distribution network and six fuel storage terminals on the islands. The base purchase price for Aloha Petroleum is approximately $240 million, subject to post-closing earn-out, certain closing adjustments, and before transaction costs and expenses. The transaction is expected to close in the fourth quarter of 2014, subject to customary closing conditions and required consents and approvals.

Susser Holdings Merger

On August 29, 2014, ETP and Susser completed the previously announced merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units.

In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.

Regency’s Acquisition of Eagle Rock’s Midstream Business

On July 1, 2014, Regency acquired Eagle Rock’s midstream business for $1.3 billion, including the issuance of 8.2 million Regency Common Units to Eagle Rock and the assumption of $499 million principal amount of Eagle Rock’s 8.375% Senior Notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units issued to ETE and borrowings under Regency’s revolving credit facility.

47

ETE Unit Repurchase

From January through May, ETE repurchased approximately $1 billion of ETE common units under its buyback program.

Sale of AmeriGas Common Units

During the nine months ended September 30, 2014, ETP sold a total of approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and for general partnership purposes. Subsequent to the sales, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.

Lake Charles LNG FERC Application

Lake Charles LNG Export, LLC and Lake Charles LNG filed an application with the FERC, seeking authorization for its proposed new liquefaction facilities and modifications to Lake Charles LNG’s existing terminal to facilitate the storage and subsequent export of LNG (the “Liquefaction Project”). In addition, Lake Charles LNG filed an application with the FERC to convert Lake Charles LNG’s existing regasification facilities from Section 7 (open access) to Section 3 status in conjunction with the Liquefaction Project. The FERC filings represent the culmination of significant front-end engineering design efforts for the Liquefaction Project and pre-filing consultations with the FERC and other federal, state and local agencies that have been underway since mid-2012.  Approval of these applications is requested from the FERC by April 1, 2015.

Quarterly Cash Distribution Increase

In October 2014, ETE announced that its Board of Directors approved an increase in its quarterly distribution to $0.4150 per unit ($1.66 annualized) on ETE Common Units for the quarter ended September 30, 2014.

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, loss on extinguishment 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.

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.

Eliminations in the tables below include the following:

• ETP’s Segment Adjusted EBITDA reflected 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA included its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star were included in eliminations.

• ETP’s Segment Adjusted EBITDA reflected the results of SUGS from March 26, 2012 to April 30, 2013. Since the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also included the results of SUGS from March 26, 2012 to April 30, 2013.

• ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the three and nine months ended September 30, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013.

48

Consolidated Results

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,172		$	942		$	230		$	3,547		$	2,967		$	580
Investment in Regency	344			172			172			856			446			410
Investment in Lake Charles LNG	51			47			4			146			139			7
Corporate and Other	(18		)	(9		)	(9		)	(73		)	(38		)	(35		)
Adjustments and Eliminations	(78		)	(103		)	25			(190		)	(250		)	60
Total	1,471			1,049			422			4,286			3,264			1,022
Depreciation, depletion and amortization	(425		)	(332		)	(93		)	(1,248		)	(962		)	(286		)
Interest expense, net of interest capitalized	(356		)	(298		)	(58		)	(1,015		)	(913		)	(102		)
Gain on sale of AmeriGas common units	14			87			(73		)	177			87			90
Gains (losses) on interest rate derivatives	(25		)	3			(28		)	(73		)	55			(128		)
Non-cash unit-based compensation expense	(20		)	(16		)	(4		)	(60		)	(43		)	(17		)
Unrealized gains (losses) on commodity risk management activities	32			22			10			(11		)	45			(56		)
Losses on extinguishment of debt	2			—			2			2			(7		)	9
LIFO valuation adjustments	(51		)	6			(57		)	(17		)	22			(39		)
Equity in earnings of unconsolidated affiliates	84			38			46			265			182			83
Adjusted EBITDA related to unconsolidated affiliates	(183		)	(165		)	(18		)	(583		)	(553		)	(30		)
Adjusted EBITDA related to discontinued operations	—			(12		)	12			(27		)	(75		)	48
Other, net	(17		)	10			(27		)	(73		)	6			(79		)
Income from continuing operations before income tax expense	526			392			134			1,623			1,108			515
Income tax expense from continuing operations	56			49			7			271			136			135
Income from continuing operations	470			343			127			1,352			972			380
Income from discontinued operations	—			13			(13		)	66			44			22
Net income	$	470		$	356		$	114		$	1,418		$	1,016		$	402

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three and nine months ended September 30, 2014 compared to the same periods last year increased primarily due to additional expense recognized by Regency of $48 million and $177 million, respectively, as a result of the completion of various organic growth projects and assets acquired from PVR, Eagle Rock and Hoover. The remainder of the increase was due to additional depreciation and amortization related to assets recently placed in service and recent acquisitions by ETP.

49

Interest Expense, Net of Interest Capitalized. Interest expense for the three and nine months ended September 30, 2014 increased primarily due to the following:

• an increase of $45 million and $101 million, respectively, of expense recognized by Regency primarily due to recent issuances of senior notes, as well as the assumption of $1.2 billion of senior notes in the PVR acquisition and $499 million of senior notes in the Eagle Rock acquisition; and

• an increase of $2 million and $16 million, respectively, of expense recognized by ETP primarily due to recent issuances of senior notes.

In addition, interest expense recognized by the Parent Company increased $10 million for the three months ended September 30, 2014 due to an increase in the principal amount of long-term debt outstanding, including $700 million of senior notes issued in May 2014. For the nine months ended September 30, 2014 interest expense recognized by the Parent Company decreased by $17 million primarily related to the repayment of $1.1 billion of borrowings under the Parent Company’s term loan in April 2013, net of interest related to incremental debt.

Gain on Sale of AmeriGas Common Units. In January 2014, June 2014 and August 2014, ETP recognized gains on the sales of 9.2 million, 8.5 million and 1.2 million AmeriGas common units, respectively, that were originally received in connection with the contribution of ETP’s propane business to AmeriGas in 2012. As of September 30, 2014, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.

Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the three and nine months ended September 30, 2014 resulted from decreases in forward interest rates, which caused ETP’s forward-starting swaps to decrease in value. Conversely, increases in forward interest rates resulted in gains on interest rate derivatives during the three and nine months ended September 30, 2013.

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.

LIFO Valuation Adjustments. LIFO valuation reserve adjustments were recorded during the three and nine months ended September 30, 2014 and 2013, respectively, for the inventory associated with ETP’s retail marketing operations 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 and Citrus. See additional discussion of Adjusted EBITDA related to unconsolidated affiliates in “Segment Operating Results” below.

Adjusted EBITDA Related to Discontinued Operations. Amounts for the nine months ended September 30, 2014 related to a marketing business that was sold by ETP effective April 1, 2014. Amounts for the three and nine months ended September 30, 2013 primarily related to Southern Union’s local distribution operations.

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

Income Tax Expense From Continuing Operations. Income tax expense is based on the earnings of our taxable subsidiaries. In addition, the nine months ended September 30, 2014 included the impact of the Lake Charles LNG Transaction, which was treated as a sale for tax purposes, resulting in $87 million of incremental income tax expense.

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Segment Operating Results

Investment in ETP

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Revenues	$	13,618		$	11,902		$	1,716		$	38,879		$	34,307		$	4,572
Cost of products sold	12,124			10,654			1,470			34,626			30,477			4,149
Gross margin	1,494			1,248			246			4,253			3,830			423
Unrealized losses (gains) on commodity risk management activities	(16		)	(8		)	(8		)	14			(45		)	59
Operating expenses, excluding non-cash compensation expense	(401		)	(337		)	(64		)	(1,031		)	(989		)	(42		)
Selling, general and administrative, excluding non-cash compensation expense	(137		)	(113		)	(24		)	(318		)	(344		)	26
LIFO valuation adjustments	51			(6		)	57			17			(22		)	39
Adjusted EBITDA related to unconsolidated affiliates	163			151			12			529			474			55
Adjusted EBITDA related to discontinued operations	—			12			(12		)	27			75			(48		)
Other	18			(5		)	23			56			(12		)	68
Segment Adjusted EBITDA	$	1,172		$	942		$	230		$	3,547		$	2,967		$	580

Gross Margin. For the three and nine months ended September 30, 2014 compared to the same periods last year, ETP’s gross margin increased $246 million and $423 million, respectively, primarily due to:

• an increase in retail marketing gross margin of $111 million and $284 million, respectively, primarily due to recent acquisitions, partially offset by unfavorable impacts of $57 million and $39 million, respectively, from non-cash LIFO valuation adjustments;

• an increase in liquids transportation and services gross margin of $80 million and $194 million, respectively, primarily as a result of an increase in transportation margin from higher volumes transported on Lone Star’s Gateway pipeline and from the startup of Lone Star’s second fractionator at Mont Belvieu, Texas in October 2013;

• an increase of $93 million and $88 million, respectively, in gross margin recognized by Sunoco Logistics. For the three months ended September 30, 2014, the increase was primarily due to expanded crude differentials and increased crude volumes from higher market demand and expansion of the crude oil trucking fleet. For the nine months ended September 30, 2014, the increase was primarily due to $45 million from crude oil pipelines as a result of higher throughput volumes related to expansion projects, $73 million from terminal facilities primarily due to higher volumes and increased margins from refined product and NGL acquisition and marketing activities, and $24 million from refined products pipelines primarily due to operating results from Sunoco Logistics’ Mariner West project. The increases for the nine months ended September 30, 2014 were partially offset by a decrease of $69 million due to lower crude margins;

• an increase of $25 million and $37 million, respectively, in gross margin from ETP’s midstream operations, primarily due to increased production and capacity from assets recently placed in service in the Eagle Ford Shale; partially offset by

• a decrease in interstate transportation and storage revenues of $53 million and $187 million, respectively, primarily due to ETP’s deconsolidation of Lake Charles LNG as of January 1, 2014 and the recognition in the second quarter of 2013 of $52 million received in connection with the buyout of a customer contract.

Unrealized Losses (Gains) on Commodity Risk Management Activities. Unrealized losses (gains) 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 nine months ended September 30, 2014 compared to the same periods last year, the changes included $7 million and $55 million, respectively, of unrealized losses related to derivatives and

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inventory adjustments in ETP’s intrastate transportation and storage operations, offset by $13 million and $2 million, respectively, of unrealized gains related to Sunoco Logistics.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2014 compared to the same periods last year, ETP’s operating expenses increased primarily due to increases of $70 million and $106 million, respectively, in ETP’s retail marketing operations due to recent acquisitions. For the nine months ended September 30, 2014, the increase was partially offset by the impact of ETP’s deconsolidation of Southern Union’s gathering and processing operations on April 30, 2013.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three months ended September 30, 2014 compared to the same period last year, the increase in ETP’s selling, general and administrative expenses included the following impacts:

• an increase of $9 million related to ETP’s retail marketing operations primarily due to recent acquisitions;

• an increase of $4 million related to ETP’s midstream operations primarily due to a reimbursement of legal fees in the prior period;

• an increase of $3 million related to ETP’s intrastate transportation and storage operations primarily related to an increase in employee-related costs; and

• an increase of $3 million related to ETP’s liquids transportation and services operations primarily due to an increase in employee-related costs.

For the nine months ended September 30, 2014 compared to the same period last year, the decrease in ETP’s selling, general and administrative expenses included the following impacts:

• a decrease of $20 million related to ETP’s interstate transportation and storage operations primarily due to an $8 million reduction from the deconsolidation of Lake Charles LNG, a $6 million reduction in professional fees, and a $5 million reduction in employee-related costs as a result of the successful integration of Southern Union’s operations;

• a decrease of $23 million related to ETP’s all other operations primarily due to costs associated with certain Sunoco activities that were recorded in the prior year; partially offset by

• an increase of $19 million related to ETP’s retail marketing operations primarily due to recent acquisitions.

Other. ETP’s other, net reflected an increase in management fees paid by ETE. In exchange for management services, ETE has agreed to pay to ETP fees totaling $95 million, $95 million and $5 million for the years ending December 31, 2014, 2015, and 2016, respectively. For the nine months ended September 30, 2014, the management fee with respect to the first two quarters of 2014 has been adjusted from amounts previously reported to reflect the impact from capitalization of portions of these fees.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the three and nine months ended September 30, 2014 consisted of the following:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2014		2013			Change			2014		2013			Change
AmeriGas	$	—	$	9		$	(9	)	$	56	$	122		$	(66	)
Citrus	84		85			(1		)	233		226			7
FEP	19		20			(1		)	56		57			(1		)
Regency	26		26			—			78		42			36
PES	21		(6		)	27			69		(9		)	78
Other	13		17			(4		)	37		36			1
Total Adjusted EBITDA related to unconsolidated affiliates	$	163	$	151		$	12		$	529	$	474		$	55

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Adjusted EBITDA related to AmeriGas decreased primarily due to a reduction of ETP’s investment due to the sale of AmeriGas common units in 2013 and 2014.

Adjusted EBITDA related to Regency increased primarily because the prior year reflected only a partial period beginning April 30, 2013. ETP’s investment in Regency is eliminated in consolidation.

Investment in Regency

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Revenues	$	1,483		$	665		$	818		$	3,524		$	1,844		$	1,680
Cost of products sold	1,051			477			574			2,517			1,309			1,208
Gross margin	432			188			244			1,007			535			472
Unrealized gains on commodity risk management activities	(16		)	(14		)	(2		)	(3		)	—			(3		)
Operating expenses, excluding non-cash compensation expense	(132		)	(80		)	(52		)	(308		)	(225		)	(83		)
Selling, general and administrative, excluding non-cash compensation expense	(39		)	(15		)	(24		)	(131		)	(69		)	(62		)
Adjusted EBITDA related to unconsolidated affiliates	86			65			21			240			188			52
Other	13			28			(15		)	51			17			34
Segment Adjusted EBITDA	$	344		$	172		$	172		$	856		$	446		$	410

Gross Margin. Regency’s gross margin increased for the three and nine months ended September 30, 2014 compared to the same periods last year primarily as a result of increased volumes in South and West Texas and North Louisiana in Regency’s gathering and processing operations, as well as $161 million and $278 million, respectively, from recent acquisitions.

Unrealized Gains on Commodity Risk Management Activities. Regency’s gains on commodity risk management activities were primarily due to mark-to-market adjustments on non-hedged commodity derivatives.

Operating Expenses, Excluding Non-Cash Compensation Expense. Regency’s operating expenses increased for the three and nine months ended September 30, 2014 compared to the same periods last year primarily as a result of recent acquisitions, in addition to organic growth in Regency’s gathering and processing operations in South and West Texas.

Adjusted EBITDA Related to Unconsolidated Affiliates. Regency’s Adjusted EBITDA attributable to unconsolidated affiliates increased for the three and nine months ended September 30, 2014 compared to the same periods last year primarily due to increases attributable to Lone Star resulting from higher volumes transported, as well as the startup of Lone Star’s second fractionator at Mont Belvieu, Texas in October 2013.

Other. Regency’s other income and deductions decreased for the three and nine months ended September 30, 2014 primarily due to a non-cash mark-to-market adjustment of the embedded derivative related to Regency’s Series A preferred units.

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Investment in Lake Charles LNG

	Three Months Ended September 30,								Nine Months Ended September 30,
	2014			2013			Change		2014			2013			Change
Revenues	$	55		$	55		$	—	$	162		$	162		$	—
Operating expenses, excluding non-cash compensation expense	(5		)	(5		)	—		(13		)	(15		)	2
Selling, general and administrative, excluding non-cash compensation expense	(1		)	(3		)	2		(4		)	(8		)	4
Other	2			—			2		1			—			1
Segment Adjusted EBITDA	$	51		$	47		$	4	$	146		$	139		$	7

Amounts reflected above included comparative amounts for the three and nine months ended September 30, 2013, which preceded ETE’s direct investment in Lake Charles LNG effective January 1, 2014.

Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.

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 Regency and cash flows from the operations of Lake Charles LNG. The amount of cash that ETP and Regency 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 from ETP and Regency.

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, Regency 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 ETP and Regency 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.

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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 (net of contributions in aid of construction costs) for the full year 2014 to be within the following ranges:

	Growth				Maintenance
	Low		High		Low		High
Direct(1):
Intrastate transportation and storage	$	150	$	160	$	30	$	35
Interstate transportation and storage	110		130		110		115
Midstream	750		850		10		15
Liquids transportation and services(2)	400		450		20		25
Retail marketing(3)	150		185		60		70
All other (including eliminations)	70		80		10		20
Total direct capital expenditures	1,630		1,855		240		280
Indirect(1):
Investment in Sunoco Logistics	2,400		2,600		65		75
Investment in Sunoco LP(3)	55		70		—		5
Total indirect capital expenditures	2,455		2,670		65		80
Total projected capital expenditures	$	4,085	$	4,525	$	305	$	360

⁽¹⁾  Indirect capital expenditures comprise those funded by ETP’s publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.

⁽²⁾  Includes 100% of Lone Star’s capital expenditures. ETP expects to receive capital contributions from Regency related to Regency’s 30% interest in Lone Star of between $95 million and $120 million.

⁽³⁾  ETP’s retail marketing operations include the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures incurred by Susser and Sunoco LP are reflected beginning on the acquisition date of August 29, 2014 and are broken out between direct and indirect amounts. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.

Sunoco Logistics expects total growth capital expenditures of approximately $2 billion in 2015, and ETP expects to publicly announce expected 2015 capital expenditures for its other operations prior to filing of its Annual Report on Form 10-K for the year ended December 31, 2014.

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 or a combination thereof.

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Regency

Regency expects its sources of liquidity to include: cash generated from operations and occasional asset sales; borrowings under the Regency Credit Facility; distributions received from unconsolidated affiliates; debt offerings; and issuance of additional partnership units.

In 2014, Regency expects to invest $1.10 billion in growth capital expenditures, of which $650 million is expected to be invested in organic growth projects in the gathering and processing operations; $100 million is expected to be invested in growth capital expenditures in its NGL services operations; and $350 million is expected to be invested in growth capital expenditures in its contract services operations. In addition, Regency expects to invest $80 million in maintenance capital expenditures in 2014, including its proportionate share related to joint ventures.

Regency may revise the timing of these expenditures as necessary to adapt to economic conditions. Regency expects to fund its growth capital expenditures with borrowings under its revolving credit facility and a combination of debt and equity issuances.

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

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013. Cash provided by operating activities during 2014 was $2.51 billion as compared to $1.85 billion for 2013. Net income was $1.42 billion and $1.02 billion for 2014 and 2013, respectively. The difference between net income and the net cash provided by operating activities for the nine months ended September 30,2014 primarily consisted of net changes in operating assets and liabilities of $120 million, gains on sales of AmeriGas common units of $177 million and other non-cash items totaling $922 million.

The non-cash activity in 2014 and 2013 consisted primarily of depreciation, depletion and amortization of $1.25 billion and $962 million, respectively, non-cash compensation expense of $60 million and $43 million, respectively, and equity in earnings of unconsolidated affiliates of $265 million and $182 million, respectively. Non-cash activity in 2014 also included deferred income taxes of $66 million.

Cash paid for interest, net of interest capitalized, was $1.06 billion and $944 million for the nine months endedSeptember 30, 2014 and 2013, respectively.

Capitalized interest was $70 million and $32 million for the nine months endedSeptember 30, 2014 and 2013, respectively.

Investing Activities

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

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013. Cash used in investing activities during 2014 was $4.57 billion as compared to $833 million for 2013. Total capital expenditures (excluding the allowance for

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equity funds used during construction and net of contributions in aid of construction costs) for 2014 were $3.68 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 2013 of $2.49 billion. We paid cash for acquisitions of $1.79 billion and received $814 million in cash from sales of AmeriGas common units during the nine months endedSeptember 30, 2014.

Financing Activities

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

Nine months ended September 30, 2014 compared to nine months ended September 30, 2013. Cash provided by financing activities during 2014 was $2.59 billion as compared to cash used in financing activities of $209 million for 2013. In 2014, ETP has received $1.13 billion in net proceeds from offerings of their common units as compared to $1.30 billion in 2013. Also in 2014, Sunoco Logistics received $593 million in net proceeds from offerings of their common units, and Regency received $162 million in net proceeds from offerings of their common units. During 2014, we had a consolidated net increase in our debt level of $3.70 billion as compared to a net increase of $329 million for 2013. We have paid distributions of $596 million and $544 million to our partners in 2014 and in 2013, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $1.36 billion and $1.05 billion in 2014 and 2013, respectively. We have also paid $1 billion to repurchase common units during the nine months ended September 30, 2014 under our buyback program.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	September 30, 2014		December 31, 2013
Parent Company Indebtedness:
ETE Senior Notes due October 15, 2020	$	1,187	$	1,187
ETE Senior Notes due January 15, 2024	1,150		450
ETE Senior Secured Term Loan, due December 2, 2019	1,400		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	800		171
Subsidiary Indebtedness:
ETP Senior Notes	10,890		11,182
Regency Senior Notes	4,899		2,800
PVR Senior Notes	789		—
Transwestern Senior Notes	870		870
Panhandle Senior Notes	1,085		1,085
Sunoco Senior Notes	965		965
Sunoco Logistics Senior Notes	2,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	800		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	689		510
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	35		35
Sunoco Logistics $1.5 billion Revolving Credit Facility due November 19, 2018	525		200
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019	270		—
Other Long-Term Debt	220		228
Unamortized premiums and fair value adjustments, net	304		301
Total	29,853		23,199
Less: Current maturities of long-term debt	1,345		637
Long-term debt and notes payable, less current maturities	$	28,508	$	22,562

The terms of our consolidated indebtedness are described in more detail in our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 27, 2014 and in Note 8 to our consolidated interim financial statements.

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ETE Term Loan Facility

In April 2014, the Parent Company amended its Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”) to increase the aggregate principal amount to $1.4 billion. The Parent Company used the proceeds from this $400 million increase to repay borrowings under its revolving credit facility and for general partnership purposes. No other significant changes were made to the terms of the ETE Term Credit Agreement, including maturity date and interest rate.

ETE Senior Notes

The Parent Company currently has outstanding an aggregate of $1.19 billion in principal amount of 7.5% senior notes due 2020 and $1.15 billion in principal amount of 5.875% senior notes due 2024.

Sunoco Logistics Senior Notes

In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044. The net proceeds from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facility and for general partnership purposes.

Regency Senior Notes

In February 2014, Regency issued $900 million aggregate principal amount of 5.875% senior notes due March 1, 2022.

In March 2014, as part of the PVR Acquisition, Regency assumed the outstanding senior notes of PVR with an aggregate notional amount of $1.2 billion. The senior notes consist of $300 million8.25% senior notes due April 15, 2018, $400 million6.5% senior notes due May 15, 2021 and $473 million8.375% senior notes due June 1, 2020. In April 2014, Regency redeemed all of the $300 million 8.25% senior notes due April 15, 2018 for $313 million. In July 2014, Regency redeemed $83 million of the $473 million 8.375% senior notes due June 1, 2020, including $8 million of accrued interest and redemption premium.

In July 2014, Regency exchanged $499 million of 8.375% senior notes due 2019 of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% senior notes due 2019 to be issued by Regency and its wholly-owned subsidiary.

In July 2014, Regency issued $700 million aggregate principal amount of 5.0% senior notes that mature on October 1, 2022.

In October 2014, Regency issued a notice of redemption to the holders of the $600 million 6.875% senior notes due December 1, 2018 with a redemption date of December 2, 2014 at a price of 103.438%. This redemption is expected to be funded through borrowings under the Regency Credit Facility.

Revolving Credit Facilities

Parent Company Credit Facility

The Parent Company increased the capacity on its revolving credit facility to $1.2 billion through two steps, in February and May. 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 September 30, 2014, we had $800 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $400 million.

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2017. 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 September 30, 2014, the ETP Credit Facility had $800 million of outstanding borrowings.

Regency Credit Facility

Regency has a $1.5 billion revolving credit facility with a $500 million uncommitted incremental facility that matures on May 21, 2018. Indebtedness under the Regency Credit Facility is secured by all of Regency’s and certain of its subsidiaries’ tangible and intangible assets and guaranteed by certain of Regency’s subsidiaries.

As of September 30, 2014, there was a balance outstanding under the Regency Credit Facility of $689 million in revolving credit loans and approximately $25 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2014, which was reduced by any letters of credit, was approximately $786 million.

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Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $1.5 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”), which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $2.25 billion under certain conditions. As of September 30, 2014, the Sunoco Logistics Credit Facility had $525 million of outstanding borrowings.

Sunoco LP Credit Facility

On September 25, 2014, Sunoco LP entered into a $1.25 billion revolving credit agreement (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 September 30, 2014, the Sunoco LP Credit Facility had $270 million of outstanding borrowings.

Covenants Related to Our Credit Agreements

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2014.

CONTRACTUAL OBLIGATIONS

In connection with the acquisition of PVR, Regency assumed the following long-term debt:

• $300 million notional amount of 8.25% senior notes due April 15, 2018. In April 2014, Regency redeemed all of the $300 million 8.25% senior notes due April 15, 2018 for $313 million.

• $400 million notional amount of 6.5% senior notes due May 15, 2021; and

• $473 million notional amount of 8.375% senior notes due June 1, 2020. In July, Regency redeemed $83 million of the $473 million 8.375% senior notes due June 1, 2020 for $91 million.

Additionally, Regency issued $900 million notional amount of 5.875% senior notes due March 1, 2022 and $700 million notional amount of 5.0% senior notes due October 1, 2022 and Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044.

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, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 19, 2014	$	0.34625
March 31, 2014	May 5, 2014	May 19, 2014	0.35875
June 30, 2014	August 4, 2014	August 19, 2014	0.38000
September 30, 2013	November 3, 2014	November 19, 2014	0.41500

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The total amounts of distributions declared and/or paid during the nine months endedSeptember 30, 2014 and 2013 were as follows (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):

	Nine Months Ended September 30,
	2014		2013
Limited Partners	$	624	$	554
General Partner interest	2		1
Class D units	2		—
Total Parent Company distributions	$	628	$	555

Cash Distributions Received by the Parent Company

The Parent Company’s cash available for distributions is primarily generated from its direct and indirect interests in ETP and Regency. Effective with the Parent Company’s acquisition of 100% of Lake Charles LNG on February 19, 2014, Lake Charles LNG’s wholly-owned subsidiaries also contribute to the Parent Company’s cash available for distributions. Our interests in ETP and Regency consist of 100% of the respective general partner interests and IDRs, as well as the following:

	ETP	Regency
Units held by wholly-owned subsidiaries:
Common units	30.8	57.2
ETP Class H units	50.2	—
Units held by less than wholly-owned subsidiaries:
Common units	—	31.4
Regency Class F units	—	6.3

As the holder of ETP’s and Regency’s IDRs, the Parent Company is entitled to an increasing share of ETP’s and Regency’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 (i) ETP’s general partner interest, Class H units and a portion of the outstanding ETP common units and (ii) Regency’s general partner interest and a portion of the outstanding Regency common units.

	Percentage of Total Distributions to IDRs	Quarterly Distribution Rate Target Amounts
		ETP	Regency
Minimum quarterly distribution	—%	$0.25	$0.35
First target distribution	—%	$0.25 to $0.275	$0.35 to $0.4025
Second target distribution	13%	$0.275 to $0.3175	$0.4025 to $0.4375
Third target distribution	23%	$0.3175 to $0.4125	$0.4375 to $0.5250
Fourth target distribution	48%	Above $0.4125	Above $0.5250

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

	Nine Months Ended September 30,
	2014			2013
Distributions from ETP:
Limited Partner interests	$	88		$	223
Class H Units held by ETE Holdings	159			51
General Partner interest	16			15
IDRs	546			528
IDR relinquishments related to previous transactions	(182		)	(107		)
Total distributions from ETP	627			710
Distributions from Regency:
Limited Partner interests	70			36
General Partner interest	4			3
IDRs	23			8
IDR relinquishment related to previous transaction	(2		)	(2		)
Total distributions from Regency	95			45
Total distributions received from subsidiaries	$	722		$	755

In connection with previous transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods, and ETP has agreed to make incremental distributions on the Class H Units in future periods. For the distributions to be paid for the nine months endedSeptember 30, 2014, the net impact of these adjustments will result in a reduction of $88 million in the distributions from ETP to ETE. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods:

	Total Year
2014 (remainder)	$	35
2015	86
2016	107
2017	85
2018	80
2019	70

The amounts reflected above include the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE over the first forty fiscal quarters commencing immediately after the consummation of the Susser Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interest and the incentive distribution rights between ETE and ETP.

Cash Distributions Paid by Subsidiaries

ETP and Regency 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.

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Cash Distributions Paid by ETP

Following are distributions declared and/or paid by ETP subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.9200
March 31, 2014	May 5, 2014	May 15, 2014	0.9350
June 30, 2014	August 4, 2014	August 14, 2014	0.9550
September 30, 2013	November 3, 2014	November 14, 2014	0.9750

The total amounts of ETP distributions declared during the nine months endedSeptember 30, 2014 and 2013 were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):

	Nine Months Ended September 30,
	2014			2013
Limited Partners:
Common Units	$	952		$	963
Class H Units	159			51
General Partner interest	16			15
IDRs	546			528
IDR relinquishments related to previous transactions	(182		)	(107		)
Total ETP distributions	$	1,491		$	1,450

Cash Distributions Paid by Regency

Following are distributions declared and/or paid by Regency subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.4750
March 31, 2014	May 8, 2014	May 15, 2014	0.4800
June 30, 2014	August 7, 2014	August 14, 2014	0.4900
September 30, 2013	November 7, 2014	November 14, 2014	0.5025

The total amounts of Regency distributions declared and/or paid during the nine months endedSeptember 30, 2014 and 2013 were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

	Nine Months Ended September 30,
	2014			2013
Limited Partners	$	567		$	289
General Partner interest	4			3
IDRs	23			8
IDR relinquishment related to previous transaction	(2		)	(2		)
Total Regency distributions	$	592		$	298

Cash Distributions Paid by Sunoco Logistics

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.

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Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 10, 2014	February 14, 2014	$	0.3312
March 31, 2014	May 9, 2014	May 15, 2014	0.3475
June 30, 2014	August 8, 2014	August 14, 2014	0.3650
September 30, 2013	November 7, 2014	November 14, 2014	0.3825

Sunoco Logistics Unit Split

On May 5, 2014, Sunoco Logistics’ Board of Directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.

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

	Nine Months Ended September 30,
	2014		2013
Limited Partners:
Common units held by public	$	160	$	126
Common units held by ETP	73		60
General Partner interest held by ETP	7		4
Incentive distribution rights held by ETP	124		83
Total distributions declared	$	364	$	273

Cash Distributions Paid by Sunoco LP

Sunoco LP 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.

Following are distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014:

Quarter Ended	Record Date	Payment Date	Rate
September 30, 2014	November 18, 2014	November 28, 2014	$	0.5457

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

	Three Months Ended September 30, 2014
Limited Partners:
Common units held by public	$	10
Common units held by ETP	8
General Partner interest and incentive distributions held by ETP	—
Total distributions declared	$	18

CRITICAL ACCOUNTING POLICIES

Disclosure of our critical accounting policies is included in our Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC on February 27, 2014.

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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, 2013, in addition to the interim unaudited consolidated financial statements, 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, 2013. There have been no material changes to our primary market risk exposures or how those exposures are managed since December 31, 2013.

Commodity Price Risk

The tables below summarize by operating entity commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of June 30, 2014 and December 31, 2013.

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.

Our consolidated balance sheets also reflect assets and liabilities related to commodity derivatives that have previously been de-designated as cash flow hedges or for which offsetting positions have been entered. Those amounts are not subject to change based on changes in prices.

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ETP

Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power, gallons for propane and barrels for NGLs, refined products and crude. Dollar amounts are presented in millions.

	September 30, 2014							December 31, 2013
	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	920,000		$	—		$	—	9,457,500		$	3		$	5
Basis Swaps IFERC/NYMEX (1)	2,882,500		(1		)	—		(487,500	)	1			—
Options – Puts	5,000,000		—			—		—		—			—
Swings Swaps IFERC	—		—			—		1,937,500		1			—
Power (Megawatt):
Forwards	343,775		—			1		351,050		1			1
Futures	(57,744	)	(1		)	—		(772,476	)	—			2
Options — Puts	(54,400	)	—			—		(52,800	)	—			—
Options — Calls	54,400		—			—		103,200		—			—
Crude (Bbls) — Futures	(81,000	)	—			1		103,000		—			1
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(7,182,500	)	(1		)	—		570,000		—			—
Swing Swaps IFERC	17,790,000		2			1		(9,690,000	)	1			—
Fixed Swaps/Futures	(8,067,500	)	(5		)	6		(8,195,000	)	13			3
Forward Physical Contracts	(9,325,164	)	—			4		5,668,559		(1		)	2
Natural Gas Liquid (Bbls) — Forwards/Swaps	(1,602,800	)	(6		)	7		(1,133,600	)	—			17
Refined Products (Bbls) — Futures	(243,000	)	14			15		(280,000	)	—			3
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(24,197,500	)	(1		)	—		(7,352,500	)	—			—
Fixed Swaps/Futures	(24,197,500	)	1			10		(50,530,000	)	(11		)	23
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(460,000	)	—			—		(1,825,000	)	—			—
Fixed Swaps/Futures	(3,220,000	)	—			1		(12,775,000	)	(3		)	6
Natural Gas Liquid (Bbls) — Forwards/Swaps	(255,000	)	1			1		(780,000	)	(1		)	4
Crude (Bbls) — Futures	—		—			—		(30,000	)	—			—

⁽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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Regency

Notional volumes are presented in MMBtu for natural gas, gallons for propane and barrels for NGLs and WTI crude oil. Dollar amounts are presented in millions.

	September 30, 2014						December 31, 2013
	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
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(13,289,000	)	$	3	$	5	(24,455,000	)	$	(2	)	$	10
Propane (Gallons) — Forwards/Swaps	(44,562,000	)	1		4		(52,122,000	)	(3		)	6
NGLs (Barrels) — Forwards/Swaps	(439,000	)	1		2		(438,000	)	1			2
WTI Crude Oil (Barrels) — Forwards/Swaps	(1,715,000	)	3		16		(521,000	)	(1		)	5

Interest Rate Risk

As of September 30, 2014, we and our subsidiaries had $5.12 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $51 million annually. We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements. To the extent that we have debt with floating interest rates that are not hedged, our results of operations, cash flows and financial condition could be adversely affected by increases in interest rates.

The following interest rate swaps were outstanding as of September 30, 2014 and December 31, 2013 (dollars in millions), none of which are designated as hedges for accounting purposes:

Entity	Term	Type (1)	Notional Amount Outstanding
			September 30, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	—	$	400
ETP	July 2015(2)	Forward-starting to pay a fixed rate of 3.38% and receive a floating rate	200		—
ETP	July 2016(3)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	200		—
ETP	July 2017(4)	Forward-starting to pay a fixed rate of 4.18% and receive a floating rate	200		—
ETP	July 2018(4)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		—
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	—		600
ETP	June 2021	Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%	—		400
ETP	February 2023	Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%	200		400
Panhandle	November 2021	Pay a fixed rate of 3.82% and receive a floating rate	125		275

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

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

66

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in losses on interest rate derivatives) of $124 million as of September 30, 2014. For the $200 million of interest rate swaps whereby we pay a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $2 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. For Panhandle’s interest rate swaps, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $1 million.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Under the supervision and with the participation of senior management, including the President (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2014 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

Our subsidiary, Regency, closed its acquisition of Hoover on February 3, 2014, its acquisition of PVR on March 21, 2014 and its acquisition of Eagle Rock’s midstream operations on July 1, 2014. We have begun the evaluation of the internal control structures of these entities, and we expect that evaluation to continue during the remainder of 2014. In recording these acquisitions, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of these entities from the date of acquisition that are included in our results of operations for the three months ended September 30, 2014. None of the changes resulting from the Hoover, PVR and Eagle Rock Midstream acquisitions were in response to any identified deficiency or weakness in our internal control over financial reporting other than changes resulting from these acquisitions.

Our subsidiary, ETP, closed on the Susser Merger on August 29, 2014. We have begun the evaluation of the internal control structure of Susser. We expect that evaluation to continue during the remainder of 2014. In recording the Susser Merger, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of Susser from the date of acquisition that are included in our results of operations for the three months ended September 30, 2014.

There have been no changes in our internal controls, other than those discussed above, over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

67

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2013 and Note 13 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2014.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in our Annual Report on Form 10-K for our previous fiscal year ended December 31, 2013.

ITEM 6. EXHIBITS

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

Exhibit Number	Description
31.1*	Certification of 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.

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SIGNATURE

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

		ENERGY TRANSFER EQUITY, L.P.
		By:	LE GP, LLC, its General Partner
Date:	November 6, 2014	By:	/s/ Jamie Welch
			Jamie Welch
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)

69

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: November 6, 2014

/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, Jamie Welch, 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: November 6, 2014

/s/ Jamie Welch

Jamie Welch

Group Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. McReynolds, President, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

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

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

Date: November 6, 2014

/s/ John W. McReynolds

John W. McReynolds

President

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jamie Welch, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

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

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

Date: November 6, 2014

/s/ Jamie Welch

Jamie Welch

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.

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Supplemental Financial Statement Information (Tables)

9 Months Ended

Sep. 30, 2014

Schedule Of Balance Sheets

BALANCE SHEETS

(unaudited)

	September 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9		$	8
Accounts receivable from related companies	13			5
Other current assets	1			—
Total current assets	23			13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,303			3,841
INTANGIBLE ASSETS, net	11			14
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	49			41
Total assets	$	5,395		$	3,918
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related companies	$	77		$	11
Interest payable	63			24
Accrued and other current liabilities	3			3
Total current liabilities	143			38
LONG-TERM DEBT, less current maturities	4,540			2,801
OTHER NON-CURRENT LIABILITIES	3			1
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	687			1,066
Class D Units	18			6
Accumulated other comprehensive income	5			9
Total partners’ capital	709			1,078
Total liabilities and partners’ capital	$	5,395		$	3,918

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(20	)	$	(11	)	$	(83	)	$	(40	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(57		)	(47		)	(147		)	(164		)
Gains on interest rate derivatives	—			3			—			9
Equity in earnings of unconsolidated affiliates	269			207			756			573
Other, net	(2		)	(1		)	(4		)	(11		)
INCOME BEFORE INCOME TAXES	190			151			522			367
Income tax expense (benefit)	2			—			2			(1		)
NET INCOME	188			151			520			368
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1			1			1
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	—			—			1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	188		$	150		$	518		$	367

Parent Company [Member]

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended September 30,
	2014			2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	704		$	650
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds received in acquisitions and other transactions, net	—			1,332
Contributions to unconsolidated affiliate	(30		)	(8		)
Purchase of additional interest in Regency	(800		)	—
Payments received on note receivable from affiliate	—			166
Net cash used in investing activities	(830		)	1,490
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,820			440
Principal payments on debt	(1,082		)	(1,603		)
Distributions to partners	(596		)	(544		)
Redemption of Preferred Units	—			(340		)
Units repurchased under buyback program	(1,000		)	—
Debt issuance costs	(15		)	(2		)
Net cash used in financing activities	127			(2,049		)
INCREASE IN CASH AND CASH EQUIVALENTS	1			91
CASH AND CASH EQUIVALENTS, beginning of period	8			9
CASH AND CASH EQUIVALENTS, end of period	$	9		$	100

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Equity Narrative (Details) (USD $)	4 Months Ended	9 Months Ended				9 Months Ended					1 Months Ended		9 Months Ended		1 Months Ended
	May 01, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 ETP [Member]	Sep. 30, 2014 Regency [Member]	Sep. 30, 2014 Sunoco Logistics [Member]	Sep. 30, 2014 Sunoco LP [Member]	Sep. 30, 2014 Equity Distribution Agreement entered in September 2014 [Member] Sunoco Logistics [Member]	Sep. 30, 2014 Equity distribution agreement [Member] ETP [Member]	Sep. 30, 2014 Equity distribution agreement [Member] Regency [Member]	Jul. 31, 2014 ETE Common Holdings [Member] Regency [Member]	Jun. 30, 2014 ETE Common Holdings [Member] Regency [Member]	Sep. 30, 2014 Equity Distribution Agreement entered in May 2014 [Member] Sunoco Logistics [Member]	Sep. 30, 2014 Susser Merger [Member]	Feb. 28, 2014 Hoover Midstream Acquisition [Member] Common Units [Member] Regency [Member]	Mar. 21, 2014 PVR Acquisition [Member] Common Units [Member] Regency [Member]	Mar. 21, 2014 Eagle Rock Midstream Acquisition [Member] Common Units [Member] Regency [Member]	Oct. 31, 2014 ETP [Member]	Sep. 30, 2014 Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] Sunoco Logistics [Member]	Sep. 30, 2014 Sunoco LP $1.25 Billion Revolving Credit Facility Due September 2019 [Member] Sunoco LP [Member]
Units repurchased under buyback program	$ 1,000,000,000	$ (1,000,000,000)
Equity Distribution Reinvestment Program, Capacity, Shares				200,000
Common Units Remaining Available to be Issued Under Distribution Reinvestment Plan																		8,000,000
Gain on Sale of Previously Unissued Stock by Subsidiary		702,000,000	(410,000,000)
Proceeds from Issuance of Common Limited Partners Units										162,000,000
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount					272,000,000				109,000,000
Relinquishment of Rights of Incentive Distributions		88,000,000												350,000,000
Proceeds from Issuance of Common Stock, net						362,000,000	359,000,000		1,030,000,000		400,000,000	400,000,000	231,000,000
Equity Distribution Agreement, Maximum Aggregate Value Of Common Units								1,000,000,000					250,000,000
Partners' Capital Account, Units, Sale of Units						7,700,000	8,000,000				16,500,000	14,400,000
Fees and Commissions									11,000,000	2,000,000			2,000,000
Stock Issued During Period, Value, Dividend Reinvestment Plan				100,000,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan				1,900,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares															4,040,471	140,400,000	8,200,000
Line of Credit Facility, Current Borrowing Capacity																			$ 1,500,000,000	$ 1,250,000,000

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Fair Value Measurements Narrative (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Fair Value Measurements [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$ 0
Debt obligations, fair value	31,230,000,000	23,970,000,000
Long-term Debt	$ 29,853,000,000	$ 23,199,000,000

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Price Risk Management Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Amount of Gain (Loss) Recognized (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 0	$ 3	$ (6)	$ 5
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	1	0	(5)	4
Amount of Gain/(Loss) Recognized in Income on Derivatives	22	(18)	(77)	22
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(4)	(11)	(2)	(12)
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	0	3	(6)	5
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	1	0	(5)	4
Amount of Gain/(Loss) Recognized in Income on Derivatives	52	(34)	9	(20)
Commodity Derivatives [Member] | Deferred Gas Purchases [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	0	0	0	(3)
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(25)	3	(73)	55
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (1)	$ 24	$ (11)	$ 2

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Equity Table - Change In ETE Common Units (Details) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Partners' Capital Notes [Abstract]
Outstanding at December 31, 2013	559.9
Stock Repurchased During Period, Shares	(21.1)
Outstanding at September 30, 2014	538.8

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Reportable Segments Table - Revenues from External Customers by Segment (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Segment Reporting Information [Line Items]
Revenues	$ 14,987	$ 12,486	$ 42,210	$ 35,728
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	13,618	11,902	38,879	34,307
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	1,483	665	3,524	1,844
Natural Resources [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	18	0	40	0
Gathering And Processing [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	1,387	603	3,254	1,671
Corporate and Other [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	2	4	13	14
Contract Services [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	76	58	217	159
Intersegment [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	45	54	101	93
Intersegment [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	102	32	242	48
Other Segments [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	482	434	1,610	1,333
Liquids Transportation And Services [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	1,165	537	2,844	1,303
Midstream [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	311	334	915	973
Interstate Transportation and Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	254	296	794	973
Intrastate Transportation And Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	559	502	2,075	1,705
Investment in Sunoco Logistics [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	4,862	4,502	14,080	12,215
Retail Marketing [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	5,985	5,297	16,561	15,805
External Customers [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	13,573	11,848	38,778	34,214
External Customers [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	$ 1,381	$ 633	$ 3,282	$ 1,796

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Cash And Cash Equivalents Table - Schedule of Non-Cash Investing & Financing Activities (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 399	$ 260
Net gains (losses) from subsidiary common unit transactions	702	(410)
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed in acquisition	1,887	0
Long term debt exchanged in connection with acquisition	499	0
PVR, Hoover and Eagle Rock Acquisitions [Member]
NON-CASH FINANCING ACTIVITIES:
Partners' Capital Account, Acquisitions	4,281	0
Subsidiary units issued in Susser Merger [Member]
NON-CASH FINANCING ACTIVITIES:
Partners' Capital Account, Acquisitions	$ 1,312	$ 0

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Equity (Tables)

9 Months Ended

Sep. 30, 2014

Schedule of Net IDR Subsidies [Table Text Block]

	Total Year
2014 (remainder)	$	35
2015	86
2016	107
2017	85
2018	80
2019	70

Change In ETE Common Units

The change in ETE Common Units during the nine months ended September 30, 2014 was as follows:

	Number of Units
Outstanding at December 31, 2013	559.9
Repurchase of units under buyback program	(21.1	)
Outstanding at September 30, 2014	538.8

Accumulated Other Comprehensive Income

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

	September 30, 2014			December 31, 2013
Available-for-sale securities	$	3		$	2
Foreign currency translation adjustment	(4		)	(1		)
Net loss on commodity related hedges	(1		)	(4		)
Actuarial gain related to pensions and other postretirement benefits	54			56
Investments in unconsolidated affiliates, net	2			8
Subtotal	54			61
Amounts attributable to noncontrolling interest	(49		)	(52		)
Total AOCI, net of tax	$	5		$	9

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, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 19, 2014	$	0.34625
March 31, 2014	May 5, 2014	May 19, 2014	0.35875
June 30, 2014	August 4, 2014	August 19, 2014	0.38000
September 30, 2014	November 3, 2014	November 19, 2014	0.41500

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, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.9200
March 31, 2014	May 5, 2014	May 15, 2014	0.9350
June 30, 2014	August 4, 2014	August 14, 2014	0.9550
September 30, 2014	November 3, 2014	November 14, 2014	0.9750

Regency [Member]

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

Following are distributions declared and/or paid by Regency subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.4750
March 31, 2014	May 8, 2014	May 15, 2014	0.4800
June 30, 2014	August 7, 2014	August 14, 2014	0.4900
September 30, 2014	November 7, 2014	November 14, 2014	0.5025

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, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 10, 2014	February 14, 2014	$	0.3312
March 31, 2014	May 9, 2014	May 15, 2014	0.3475
June 30, 2014	August 8, 2014	August 14, 2014	0.3650
September 30, 2014	November 7, 2014	November 14, 2014	0.3825

Sunoco LP [Member]

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

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014:

Quarter Ended	Record Date	Payment Date	Rate
September 30, 2014	November 18, 2014	November 28, 2014	$	0.5457

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Supplemental Financial Statement Information Table - Balance Sheets (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Cash and cash equivalents	$ 1,108	$ 590	$ 1,177	$ 372
Accounts receivable from related companies	51	63
Other current assets	307	312
Total current assets	8,042	6,536
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,633	4,014
INTANGIBLE ASSETS, net	5,504	2,264
GOODWILL	7,867	5,894
OTHER NON-CURRENT ASSETS, net	897	922
Total assets	64,681	50,330
Accounts payable	4,694	3,834
Accounts payable to related companies	6	14
Interest payable	410	357
Price risk management liabilities	9	53
Accrued and other current liabilities	2,108	1,678
Current maturities of long-term debt	1,345	637
Total current liabilities	8,431	6,500
LONG-TERM DEBT, less current maturities	28,508	22,562
PREFERRED UNITS OF SUBSIDIARY	32	32
OTHER NON-CURRENT LIABILITIES	1,060	1,019
COMMITMENTS AND CONTINGENCIES
General Partner	(1)	(3)
Common Unitholders	687	1,066
Class D Units	18	6
Accumulated other comprehensive income	5	9
Total partners’ capital	709	1,078
Total liabilities and equity	64,681	50,330
Parent Company [Member]
Cash and cash equivalents	9	8	100	9
Accounts receivable from related companies	13	5
Other current assets	1	0
Total current assets	23	13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,303	3,841
INTANGIBLE ASSETS, net	11	14
GOODWILL	9	9
OTHER NON-CURRENT ASSETS, net	49	41
Total assets	5,395	3,918
Accounts payable to related companies	77	11
Interest payable	63	24
Accrued and other current liabilities	3	3
Total current liabilities	143	38
LONG-TERM DEBT, less current maturities	4,540	2,801
OTHER NON-CURRENT LIABILITIES	3	1
COMMITMENTS AND CONTINGENCIES
General Partner	(1)	(3)
Common Unitholders	687	1,066
Class D Units	18	6
Accumulated other comprehensive income	5	9
Total partners’ capital	709	1,078
Total liabilities and equity	$ 5,395	$ 3,918

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Other Information Table - Accrued and Other Current Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Other Information [Abstract]
Interest payable	$ 410	$ 357
Customer advances and deposits	95	142
Accrued Capital Expenditures	398	260
Accrued wages and benefits	204	173
Taxes payable other than income taxes	343	211
Income taxes payable	127	4
Deferred income taxes	132	119
Other	399	412
Total accrued and other current liabilities	$ 2,108	$ 1,678

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Equity Table - IDR Schedule (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2014 IDR Relinquishment [Member]	Dec. 31, 2019 IDR Relinquishment [Member]	Dec. 31, 2018 IDR Relinquishment [Member]	Dec. 31, 2017 IDR Relinquishment [Member]	Dec. 31, 2016 IDR Relinquishment [Member]	Dec. 31, 2015 IDR Relinquishment [Member]
Subsequent Event [Line Items]
Relinquishment of Rights of Incentive Distributions	$ 88	$ 35	$ 70	$ 80	$ 85	$ 107	$ 86

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Reportable Segments Table - Segment Assets (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets	$ 64,681	$ 50,330
Investment In ETP [Member]
Assets	48,571	43,702
Investment In Regency [Member]
Assets	17,180	8,782
Investment in Lake Charles LNG [Member]
Assets	1,170	1,338
Corporate and Other [Member]
Assets	804	720
Adjustments And Eliminations [Member]
Assets	$ (3,044)	$ (4,212)

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Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 2,507	$ 1,847
Proceeds received in acquisitions and other transactions, net	(1,794)	(5)
Net cash used in investing activities	(4,574)	(833)
Proceeds from borrowings	12,044	9,768
Repayments of long-term debt	(8,342)	(9,439)
Distributions to partners	596	544
Redemption of Preferred Units	0	340
Units repurchased under buyback program	1,000	0
Debt issuance costs	(61)	(56)
Net cash used in financing activities	2,585	(209)
INCREASE IN CASH AND CASH EQUIVALENTS	518	805
CASH AND CASH EQUIVALENTS, beginning of period	590	372
CASH AND CASH EQUIVALENTS, end of period	1,108	1,177
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	704	650
Proceeds received in acquisitions and other transactions, net	0	1,332
Contributions to unconsolidated affiliate	(30)	(8)
Purchase of additional interest in Regency	800	0
Payments received on note receivable from affiliate	0	166
Net cash used in investing activities	(830)	1,490
Proceeds from borrowings	2,820	440
Repayments of long-term debt	(1,082)	(1,603)
Distributions to partners	(596)	(544)
Redemption of Preferred Units	0	(340)
Units repurchased under buyback program	(1,000)	0
Debt issuance costs	(15)	(2)
Net cash used in financing activities	127	(2,049)
INCREASE IN CASH AND CASH EQUIVALENTS	1	91
CASH AND CASH EQUIVALENTS, beginning of period	8	9
CASH AND CASH EQUIVALENTS, end of period	$ 9	$ 100

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Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Intersegment Revenues	$ 14,987	$ 12,486	$ 42,210	$ 35,728
Investment In ETP [Member]
Intersegment Revenues	13,618	11,902	38,879	34,307
Investment In Regency [Member]
Intersegment Revenues	1,483	665	3,524	1,844
Adjustments And Eliminations [Member]
Intersegment Revenues	(169)	(136)	(355)	(585)
Intersegment [Member] | Investment In ETP [Member]
Intersegment Revenues	45	54	101	93
Intersegment [Member] | Investment In Regency [Member]
Intersegment Revenues	102	32	242	48
External Customers [Member] | Investment In ETP [Member]
Intersegment Revenues	13,573	11,848	38,778	34,214
External Customers [Member] | Investment In Regency [Member]
Intersegment Revenues	1,381	633	3,282	1,796
External Customers [Member] | Investment in Lake Charles LNG [Member]
Intersegment Revenues	$ 55	$ 55	$ 162	$ 162

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Related Party Transactions Related Party Revenue (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Related Party Transactions [Abstract]
Revenue from Related Parties	$ 261	$ 387	$ 951	$ 1,080

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Operations And Organization Accounting policy (Policies)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

New Accounting Pronouncements, Policy [Policy Text Block]

New 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. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. 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 April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.

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Fair Value Measurements Table - Reconciliation of Level 3 Derivatives (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014 Level 3 [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Level 3 [Member] Fair Value, Measurements, Recurring [Member]
Balance, December 31, 2013		$ (30)	$ (19)
Net unrealized loss included in other income (expense)	11
Balance, September 30, 2014		$ (30)	$ (19)

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Acquisitions Regency PPA (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jul. 01, 2014	Jul. 01, 2014 Eagle Rock Midstream Acquisition [Member]	Mar. 21, 2014 PVR Acquisition [Member]	Mar. 03, 2014 Hoover Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets						$ 115	$ 149
Business Acquisition, Pro Forma Revenue	14,987	13,042	43,036	37,310
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets								5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					1,329		2,716	117
Business Acquisition, Purchase Price Allocation, Investments in Affilaites							62
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill							2,717	148
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Goodwill							370	30
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets					4		18
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets					1,448		6,032	300
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities					109		168
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities								5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other								2
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt					499		1,788
Business Combination, Purchase Price Allocation, Premium on Long Term Debt							99
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other					12		30
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities					620		2,085	7
Business Acquisition, Pro Forma Net Income (Loss)	188	138	496	324
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 0.35	$ 0.25	$ 0.91	$ 0.58
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 0.35	$ 0.25	$ 0.91	$ 0.58
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net					$ 828		$ 3,947	$ 293

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Reportable Segments Table - Segment Adjusted EBITDA (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 1,471	$ 1,049	$ 4,286	$ 3,264
Depreciation, depletion and amortization	(425)	(332)	(1,248)	(962)
Interest Expense, net of interest capitalized	(356)	(298)	(1,015)	(913)
Gain on sale of AmeriGas common units	14	87	177	87
Gains (losses) on interest rate derivatives	(25)	3	(73)	55
Non-cash unit-based compensation expense	(20)	(16)	(60)	(43)
Unrealized Gain (Loss) on commodity risk management activities	32	22	(11)	45
Gains (losses) on extinguishment of debt	2	0	2	(7)
LIFO valuation adjustment	(51)	6	(17)	22
Equity in earnings of unconsolidated affiliates	84	38	265	182
Adjusted EBITDA related to unconsolidated affiliates	(183)	(165)	(583)	(553)
Adjusted EBITDA related to discontinued operations	0	(12)	(27)	(75)
Other, net	(17)	10	(73)	6
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	526	392	1,623	1,108
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,172	942	3,547	2,967
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	344	172	856	446
Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	51	47	146	139
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(18)	(9)	(73)	(38)
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ (78)	$ (103)	$ (190)	$ (250)

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Other Information (Tables)

9 Months Ended

Sep. 30, 2014

Other Information [Abstract]

Other Current Assets

Other current assets consisted of the following:

	September 30, 2014		December 31, 2013
Deposits paid to vendors	$	46	$	49
Prepaid expenses and other	261		263
Total other current assets	$	307	$	312

Accrued And Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	September 30, 2014		December 31, 2013
Interest payable	$	410	$	357
Customer advances and deposits	95		142
Accrued capital expenditures	398		260
Accrued wages and benefits	204		173
Taxes payable other than income taxes	343		211
Income taxes payable	127		4
Deferred income taxes	132		119
Other	399		412
Total accrued and other current liabilities	$	2,108	$	1,678

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Debt Obligations Narrative (Details) (USD $)											1 Months Ended							9 Months Ended		9 Months Ended																	1 Months Ended
	Sep. 30, 2014 ETP [Member]	Dec. 31, 2013 ETP [Member]	Sep. 30, 2014 Sunoco Logistics [Member]	Dec. 31, 2013 Sunoco Logistics [Member]	Sep. 30, 2014 Regency [Member]	Dec. 31, 2013 Regency [Member]	Sep. 30, 2014 PVR [Member]	Mar. 21, 2014 PVR [Member]	Dec. 31, 2013 PVR [Member]	Sep. 30, 2014 5.875% Senior Notes due January 15, 2024 [Member] Parent Company [Member]	Apr. 30, 2014 ETE Senior Secured Term Loan due December 2, 2019 [Member]	Sep. 30, 2014 ETE Senior Secured Revolving Credit Facilities [Member]	May 01, 2014 ETE Senior Secured Revolving Credit Facilities [Member]	Sep. 30, 2014 5.30% Senior Notes due April 2024 [Member] Sunoco Logistics [Member]	Sep. 30, 2014 4.25% Senior Notes due April 2024 [Member] Sunoco Logistics [Member]	Sep. 30, 2014 ETE 7.5% Senior Notes due 2020 [Member]	Sep. 30, 2014 5.875% Senior Notes due March 1, 2022 [Member] Regency [Member]	Sep. 30, 2014 8.25% Senior Notes due April 15, 2015 [Member] PVR [Member]	Sep. 30, 2014 6.5% Senior Notes due May 15, 2021 [Member] PVR [Member]	Sep. 30, 2014 8.375% Senior Notes due June 1, 2020 [Member] PVR [Member]	Jul. 01, 2014 8.375% Senior Notes due June 1, 2020 [Member] Eagle Rock [Member]	Sep. 30, 2014 5.0% Senior Notes due October 1, 2022 [Member] Regency [Member]	Sep. 30, 2014 ETP Revolving Credit Facility, due October 2017 [Member] ETP [Member]	Sep. 30, 2014 Regency Credit Facility [Member]	Sep. 30, 2014 Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] Sunoco Logistics [Member]	Sep. 30, 2014 Sunoco LP $250 Million Revolving Credit Facility Due September 2017 [Member] Sunoco LP [Member]	Sep. 30, 2014 Uncommitted Incremental Facility [Member] Regency Credit Facility [Member]	Sep. 30, 2014 Sublimit [Member] Regency Credit Facility [Member]	Sep. 01, 2014 Sublimit [Member] Regency Credit Facility [Member]	Sep. 30, 2014 ETE Senior Secured Term Loan due December 2, 2018 [Member] Parent Company [Member]	Dec. 31, 2013 ETE Senior Secured Term Loan due December 2, 2018 [Member] Parent Company [Member]	Sep. 30, 2014 5.875% Senior Notes due January 15, 2024 [Member] Parent Company [Member]	Dec. 31, 2013 5.875% Senior Notes due January 15, 2024 [Member] Parent Company [Member]	Sep. 30, 2014 5.875% Senior Notes due January 15, 2024 [Member] May 2014 [Member] Parent Company [Member]	Sep. 30, 2014 ETE 7.5% Senior Notes due 2020 [Member] Parent Company [Member]	Dec. 31, 2013 ETE 7.5% Senior Notes due 2020 [Member] Parent Company [Member]	Oct. 31, 2014 Subsequent Event [Member] 8.25% Senior Notes due April 15, 2015 [Member] Regency [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity											$ 1,400,000,000		$ 1,200,000,000										$ 2,500,000,000		$ 1,500,000,000	$ 1,250,000,000
Line Of Credit Facility, Additional Borrowing Capacity Subject To Lender Approval																										250,000,000
Repayments of Lines of Credit											400,000,000
Line of Credit Facility, Amount Outstanding																							800,000,000	689,000,000	525,000,000	270,000,000				800,000,000	171,000,000
Line of Credit Facility, Remaining Borrowing Capacity												400,000,000
Letters of Credit Outstanding, Amount																								25,000,000
Senior Notes	10,890,000,000	11,182,000,000	2,975,000,000	2,150,000,000	4,899,000,000	2,800,000,000	789,000,000	1,200,000,000	0					700,000,000	300,000,000		900,000,000	300,000,000	400,000,000	473,000,000	499,000,000	700,000,000										1,150,000,000	450,000,000	700,000,000	1,187,000,000	1,187,000,000
Payments of Debt Extinguishment Costs																		313,000,000		91,000,000
Debt Instrument, Increase, Accrued Interest																				8,000,000
Extinguishment of Debt, Amount																		300,000,000		83,000,000																	600,000,000
Debt Instrument, Interest Rate, Stated Percentage										5.875%				5.30%	4.25%	7.50%	5.875%	8.25%	6.50%	8.375%		5.00%												5.875%
Debt Instrument, Redemption Price, Percentage																																					103.438%
Line of Credit Facility, Maximum Borrowing Capacity																								$ 1,500,000,000	$ 2,250,000,000		$ 500,000,000	$ 100,000,000	$ 50,000,000

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Price Risk Management Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Total derivatives assets	$ 144	$ 320
Total derivatives liabilities	245	389
Designated as Hedging Instrument [Member]
Total derivatives assets	2	3
Total derivatives liabilities	3	18
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	2	3
Total derivatives liabilities	3	18
Not Designated as Hedging Instrument [Member]
Total derivatives assets	142	317
Total derivatives liabilities	242	371
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	114	227
Total derivatives liabilities	110	209
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	25	43
Total derivatives liabilities	16	48
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	3	47
Total derivatives liabilities	86	95
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ 30	$ 19

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) (USD $)	3 Months Ended				9 Months Ended							1 Months Ended							9 Months Ended	1 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Jan. 09, 2014	Dec. 31, 2013	Apr. 30, 2013 Regency 4.50% Senior Notes Due 2023 [Member]	Nov. 30, 2012 FGT [Member]	Sep. 30, 2013 FGT [Member] I-595 Project [Member]	Sep. 30, 2013 FGT [Member] Turnpike/State Road 91 [Member]	Jan. 31, 2012 AmeriGas [Member]	Sep. 30, 2014 Plaintiff [Member]	Sep. 30, 2014 PVR [Member]	Sep. 30, 2014 Sunoco [Member]	Sep. 30, 2014 SUGS [Member]	Sep. 30, 2013 Attorney General of Commonwealth [Member]
Proceeds from Legal Settlements												$ 100,000,000
Loss Contingency, Damages Awarded, Value					24,000,000								19,000,000	1,000,000
Contingent Residual Support Agreement, Amount															1,550,000,000
Debt Instrument, Interest Rate, Stated Percentage											4.50%
Guarantor Obligations, Current Carrying Value									600,000,000		600,000,000
Lease Expiration Date					Dec. 31, 2056
Operating Leases, Rent Expense	31,000,000	[1]	33,000,000	[1]	90,000,000	[1]	98,000,000	[1]
Operating Leases, Rent Expense, Contingent Rentals	8,000,000		8,000,000		17,000,000		18,000,000
Invoices in Dispute					17,000,000
Loss Contingency, Estimate of Possible Loss																30,000,000	21,000,000
Loss Contingency Accrual, at Carrying Value	42,000,000				42,000,000					46,000,000
Amounts recorded in balance sheets for contingencies and current litigation not disclosed	0				0
Legal Fees																				19,000,000
Percentage Of Recovery																				50.00%
Reimbursement expert and consultant cost, maximum																				150,000
Payments for Environmental Liabilities	10,000,000		9,000,000		27,000,000		27,000,000
Site Contingency, Number of Sites Needing Remediation																		49
Environmental Expense and Liabilities																			$ 1,000,000

[1] (1) Includes contingent rentals totaling $8 million for the three months ended September 30, 2014 and 2013, and $17 million and $18 million for the nine months ended September 30, 2014 and 2013, respectively.

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Inventories Table - Inventory Balances (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Inventory, Net [Abstract]
Natural gas and NGLs	$ 404	$ 523
Crude oil	459	488
Refined products	597	597
Appliances, parts and fittings and other	320	199
Total inventories	$ 1,780	$ 1,807

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Advances to and Investments in Unconsolidated Affiliates

9 Months Ended

Sep. 30, 2014

INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract]

Advances to and Investments in Unconsolidated Advances to Affiliates

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The following investments in unconsolidated affiliates are reflected in our consolidated financial statements using the equity method:

• AmeriGas. During the nine months ended September 30, 2014, ETP sold a total of approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and for general partnership purposes. Subsequent to the sales, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.

• Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.

• FEP. ETP owns a 50% interest in the FEP, which owns a natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company, LLC in Panola County, Mississippi.

• HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the Regency Intrastate Gas System, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through an intrastate pipeline system.

• MEP. Regency owns a 50% interest in MEP, which owns natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.

The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenue	$	919	$	883	$	3,703	$	3,324
Operating income	206		196		881		839
Net income	82		64		505		460

In addition to the equity method investments described above, our subsidiaries have other equity method investments, which are not significant to our consolidated financial statements.

In May 2014, Sunoco Logistics entered into a joint agreement to form Bayview Refining Company, LLC (“Bayview”). Bayview will construct and operate a facility that will process crude oil into intermediate petroleum products. Sunoco Logistics will fund construction of the facility through contributions proportionate to its 49% economic and voting interests, with the remaining portion funded by the joint owner through a promissory note entered into with Sunoco Logistics. Through September 30, 2014, the joint owners have made contributions totaling $21 million. The facility is expected to commence operations in the second half of 2015. Bayview is a variable interest entity of which Sunoco Logistics is not the primary beneficiary. As a result, Sunoco Logistics’ interest in Bayview is reflected as an equity method investment.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Environmental Exit Cost [Line Items]
Current	$ 73	$ 47
Non-current	321	356
Total environmental liabilities	$ 394	$ 403

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Acquisitions Susser PPA (Details) (USD $) In Millions, unless otherwise specified		0 Months Ended
	Jul. 01, 2014	Aug. 01, 2014 Susser Merger [Member]	Aug. 29, 2014 Susser Merger [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Net of Cash Received			$ 1,716
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets			422
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	1,329		1,065
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Goodwill			1,605	[1]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill			481
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	4		27
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	1,448		3,600
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	109		377
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	499		564
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent			432
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	12		40
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value			404
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	620		1,817
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	828		1,783
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents			67
Business Combination, Consideration Transferred		$ 1,800

[1] (1) None of the goodwill is expected to be deductible for tax purposes.

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Inventories (Tables)

9 Months Ended

Sep. 30, 2014

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:

	September 30, 2014		December 31, 2013
Natural gas and NGLs	$	404	$	523
Crude oil	459		488
Refined products	597		597
Appliances, parts and fittings and other	320		199
Total inventories	$	1,780	$	1,807

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Cash And Cash Equivalents (Tables)

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Information [Abstract]

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

Non-cash investing and financing activities were as follows:

	Nine Months Ended September 30,
	2014		2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	399	$	260
Net gains (losses) from subsidiary common unit transactions	$	702	$	(410	)
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions	$	4,281	$	—
Subsidiary issuances of common units in connection with Susser Merger	$	1,312	$	—
Long-term debt assumed in PVR Acquisition	$	1,887	$	—
Long-term debt exchanged in Eagle Rock Midstream Acquisition	$	499	$	—

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Equity Table - Quarterly Distributions of Available Cash (Details) (USD $)	3 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013
Sunoco LP [Member]
Distribution Made to Limited Partner, Date of Record	Nov. 18, 2014
Distribution Made to Limited Partner, Distribution Date	Nov. 28, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.5457
Parent Company [Member]
Distribution Made to Limited Partner, Date of Record	Nov. 03, 2014	Aug. 04, 2014	May 05, 2014	Feb. 07, 2014
Distribution Made to Limited Partner, Distribution Date	Nov. 19, 2014	Aug. 19, 2014	May 19, 2014	Feb. 19, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.415	$ 0.380000	$ 0.35875	$ 0.34625
ETP [Member]
Distribution Made to Limited Partner, Date of Record	Nov. 03, 2014	Aug. 04, 2014	May 05, 2014	Feb. 07, 2014
Distribution Made to Limited Partner, Distribution Date	Nov. 14, 2014	Aug. 14, 2014	May 15, 2014	Feb. 14, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.97500	$ 0.95500	$ 0.935	$ 0.92000
Regency [Member]
Distribution Made to Limited Partner, Date of Record	Nov. 07, 2014	Aug. 07, 2014	May 08, 2014	Feb. 07, 2014
Distribution Made to Limited Partner, Distribution Date	Nov. 14, 2014	Aug. 14, 2014	May 15, 2014	Feb. 14, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.5025	$ 0.490	$ 0.480	$ 0.475
Sunoco Logistics [Member]
Distribution Made to Limited Partner, Date of Record	Nov. 07, 2014	Aug. 08, 2014	May 09, 2014	Feb. 10, 2014
Distribution Made to Limited Partner, Distribution Date	Nov. 14, 2014	Aug. 14, 2014	May 15, 2014	Feb. 14, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.3825	$ 0.3650	$ 0.3475	$ 0.3312

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Advances to and Investments in Unconsolidated Affiliates Narrative (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended					9 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 AmeriGas [Member]	Aug. 01, 2014 AmeriGas [Member]	Sep. 30, 2014 Citrus [Member]	Sep. 30, 2014 FGT [Member]	Sep. 30, 2014 Fayetteville Express Pipeline, LLC [Member]	Sep. 30, 2014 RIGS Haynesville Partnership Co. [Member]	Sep. 30, 2014 Midcontinent Express Pipeline, LLC [Member]	Sep. 30, 2014 Bayview Refining Company, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investment Owned, Balance, Shares				3.1
AmeriGas common units sold by ETP			18.9
Proceeds from ETP's sale of AmeriGas common units	$ 814	$ 346
Interest ownership					50.00%		50.00%	49.99%	50.00%	49.00%
Percentage Ownership Operating Facility						100.00%
Advances to affiliates, net of repayments										$ 21

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

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 September 30, 2014 and December 31, 2013 based on inputs used to derive their fair values:

	Fair Value Measurements at September 30, 2014
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	3		$	—		$	3		$	—
Commodity derivatives:
Condensate — Forward Swaps	4			—			4			—
Natural Gas:
Basis Swaps IFERC/NYMEX	6			6			—			—
Swing Swaps IFERC	6			1			5			—
Fixed Swaps/Futures	75			69			6			—
Forward Physical Swaps	1			—			1			—
Natural Gas Liquids — Forwards/Swaps	16			13			3			—
Power:
Forwards	2			—			2			—
Futures	1			1			—			—
Refined Products — Futures	19			19			—			—
Total commodity derivatives	130			109			21			—
Total assets	$	133		$	109		$	24		$	—
Liabilities:
Interest rate derivatives	$	(86	)	$	—		$	(86	)	$	—
Embedded derivatives in the Regency Preferred Units	(30		)	—			—			(30		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(8		)	(8		)	—			—
Swing Swaps IFERC	(5		)	(1		)	(4		)	—
Fixed Swaps/Futures	(75		)	(73		)	(2		)	—
Forward Physical Swaps	(1		)	—			(1		)	—
Natural Gas Liquids — Forwards/Swaps	(19		)	(18		)	(1		)	—
Power:
Forwards	(2		)	—			(2		)	—
Futures	(2		)	(2		)	—			—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(118		)	(107		)	(11		)	—
Total liabilities	$	(234	)	$	(107	)	$	(97	)	$	(30	)

	Fair Value Measurements at December 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	47		$	—		$	47		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	8			1			7			—
Fixed Swaps/Futures	203			201			2			—
NGLs — Swaps	7			5			2			—
Power — Forwards	3			—			3			—
Refined Products — Futures	5			5			—			—
Total commodity derivatives	231			217			14			—
Total Assets	$	278		$	217		$	61		$	—
Liabilities:
Interest rate derivatives	$	(95	)	$	—		$	(95	)	$	—
Embedded derivatives in the Regency Preferred Units	(19		)	—			—			(19		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)	(4		)	—			—
Swing Swaps IFERC	(6		)	—			(6		)	—
Fixed Swaps/Futures	(206		)	(201		)	(5		)	—
Forward Physical Contracts	(1		)	—			(1		)	—
NGLs — Swaps	(9		)	(5		)	(4		)	—
Power — Forwards	(1		)	—			(1		)	—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(233		)	(215		)	(18		)	—
Total Liabilities	$	(347	)	$	(215	)	$	(113	)	$	(19	)

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 nine months endedSeptember 30, 2014.

Balance, December 31, 2013	$	(19	)
Net unrealized loss included in other income (expense)	(11		)
Balance, September 30, 2014	$	(30	)

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Net Income per Limited Partner Unit (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Reconciliation Of Net Income And Weighted Average Units

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
Income from continuing operations	$	470		$	343	$	1,352		$	972
Less: Income from continuing operations attributable to noncontrolling interest	282			195		839			623
Income from continuing operations, net of noncontrolling interest	188			148		513			349
Less: General Partner’s interest in income from continuing operations	—			1		1			1
Less: Class D Unitholder’s interest in income from continuing operations	—			—		1			—
Income from continuing operations available to Limited Partners	$	188		$	147	$	511		$	348
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	538.8			561.4		546.6			560.8
Basic income from continuing operations per Limited Partner unit	$	0.35		$	0.26	$	0.94		$	0.62
Basic income from discontinued operations per Limited Partner unit	$	—		$	0.01	$	0.01		$	0.03
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	188		$	147	$	511		$	348
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1		)	—		(2		)	(1		)
Diluted income from continuing operations available to Limited Partners	$	187		$	147	$	509		$	347
Weighted average limited partner units	538.8			561.4		546.6			560.8
Dilutive effect of unconverted unit awards	1.1			—		1.0			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	539.9			561.4		547.6			560.8
Diluted income from continuing operations per Limited Partner unit	$	0.35		$	0.26	$	0.93		$	0.62
Diluted income from discontinued operations per Limited Partner unit	$	—		$	0.01	$	0.01		$	0.03

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Acquisitions

9 Months Ended

Sep. 30, 2014

ACQUISITIONS AND DIVESTITURE [Abstract]

Acquisitions

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

2014

Susser Merger

On August 29, 2014, ETP and Susser completed the previously announced merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth.

In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.

Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.

Summary of Assets Acquired and Liabilities Assumed

We accounted for the Susser Merger using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet as of September 30, 2014 reflected the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.

The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:

	Susser
Total current assets	$	422
Property, plant and equipment	1,065
Goodwill(1)	1,605
Intangible assets	481
Other non-current assets	27
	3,600
Current liabilities	377
Long-term debt, less current maturities	564
Deferred income taxes	432
Other non-current liabilities	40
Noncontrolling interest	404
	1,817
Total consideration	1,783
Cash received	67
Total consideration, net of cash received	$	1,716

⁽¹⁾  None of the goodwill is expected to be deductible for tax purposes.

ETP incurred merger related costs related to the Susser Merger of $24 million during the three months ended September 30, 2014. Our consolidated statements of operations for the three and nine months endedSeptember 30, 2014 reflected revenue and net income related to Susser of $575 million and $2 million, respectively.

No pro forma information has been presented for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations.

MACS to Sunoco LP

On October 1, 2014, Sunoco LP acquired MACS from ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with net proceeds of $359 million from a public offering of 8 million Sunoco LP common units.

Aloha Petroleum Acquisition

On September 25, 2014, Sunoco LP entered into a definitive agreement to acquire Honolulu, Hawaii-based Aloha Petroleum, Ltd (“Aloha Petroleum”). Aloha Petroleum is an independent gasoline marketer and convenience store operator in Hawaii, with an extensive wholesale fuel distribution network and six fuel storage terminals on the islands. The base purchase price for Aloha Petroleum is approximately $240 million, subject to post-closing earn-out, certain closing adjustments, and before transaction costs and expenses. The transaction is expected to close in the fourth quarter of 2014, subject to customary closing conditions and required consents and approvals.

Lake Charles LNG Transaction

On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). This transaction waseffective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG.

In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 10.

Panhandle Merger

On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and the Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units), and ETP (2.2 million common units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.

Regency’s Acquisition of Eagle Rock’s Midstream Business

On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% Senior Notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Regency is accounting for the Eagle Rock Midstream Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. This acquisition is expected to complement Regency’s core gathering and processing business and is expected to further diversify Regency’s geographic presence in the Mid-Continent region, East Texas and South Texas. Our consolidated statements of operations for the three and nine months ended September 30, 2014 included revenues and net income attributable to Eagle Rock’s operations of $472 million and $18 million, respectively.

Regency’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:

Assets	At July 1, 2014
Current assets	$	115
Property, plant and equipment	1,329
Other long-term assets	4
Total assets acquired	1,448
Liabilities
Current liabilities	109
Long-term debt	499
Long-term liabilities	12
Total liabilities assumed	620
Net assets acquired	$	828

Regency’s Acquisition of PVR

On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (“PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. The PVR Acquisition enhances Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. Regency accounted for the acquisition of PVR using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our statements of operations included revenues attributable to PVR of $302 million and $653 million for the three and nine months ended September 30, 2014, respectively. Our statements of operations included net income attributable to PVR of $84 million and $119 million for the three and nine months ended September 30, 2014, respectively.

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At March 21, 2014
Current assets	$	149
Property, plant and equipment	2,716
Investment in unconsolidated affiliates	62
Intangible assets (average useful lives of 30 years)	2,717
Goodwill	370
Other long-term assets	18
Total assets acquired	6,032
Liabilities
Current liabilities	168
Long-term debt	1,788
Premium related to senior notes	99
Long-term liabilities	30
Total liabilities assumed	2,085
Net assets acquired	$	3,947

Regency’s Acquisition of Hoover

On February 3, 2014, Regency acquired certain subsidiaries of Hoover for a total purchase price of $293 million, consisting of (i) 4,040,471 Regency Common Units issued to Hoover, (ii) $184 million in cash and (iii) $2 million in asset retirement obligations assumed (the “Hoover Acquisition”). The acquisition of Hoover increases Regency’s fee-based revenue, expanding its existing footprint in the southern portion of the Delaware Basin in West Texas, and its services to producers into crude and water gathering. A portion of the consideration is being held in escrow as security for certain indemnification claims. Regency financed the cash portion of the purchase price through borrowings under its revolving credit facility. Regency accounted for the acquisition of Hoover using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our statements of operations included revenues attributable to Hoover’s operations of $11 million and $26 million for the three and nine months ended September 30, 2014, respectively. Our statements of operations included net losses of $2 million and net income of $2 million attributable to Hoover’s operations for the three and nine months ended September 30, 2014, respectively.

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At February 3, 2014
Current assets	$	5
Property, plant and equipment	117
Intangible assets (average useful lives of 30 years)	148
Goodwill	30
Total assets acquired	300
Liabilities
Current liabilities	5
Asset retirement obligations	2
Total liabilities assumed	7
Net assets acquired	$	293

The fair values of the assets acquired and liabilities assumed for the Eagle Rock Midstream, PVR and Hoover acquisitions were determined using various valuation techniques, including the income and market approaches.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2014 and 2013 are presented as if the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assume there were no other changes in operations. This pro forma information does not necessarily reflect the actual results that would have occurred had the acquisitions occurred on January 1, 2013, nor is it indicative of future results of operations. Actual results for the three months ended September 30, 2014 include PVR and the Eagle Rock midstream business for the entire period.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenues	$	14,987	$	13,042	$	43,036	$	37,310
Net income attributable to partners	188		138		496		324
Basic net income per Limited Partner unit	$	0.35	$	0.25	$	0.91	$	0.58
Diluted net income per Limited Partner unit	$	0.35	$	0.25	$	0.91	$	0.58

The pro forma consolidated results of operations include adjustments to reflect incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting and incremental interest expense related to the financing of a portion of the purchase price.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

Discontinued Operations

Discontinued operations for the nine months ended September 30, 2014 included the results of operations for a marketing business that had been recently acquired by ETP and was sold effective April 1, 2014, as well as a $39 million gain on the sale. The disposed subsidiary’s results of operations were not material during any periods in 2013; therefore, the disposed subsidiary’s results were not reclassified to discontinued operations in the prior period.

Discontinued operations for the three and nine months ended September 30, 2013 included the results of Southern Union’s distribution operations.

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Debt Obligations Debt Table (Tables)

9 Months Ended

Sep. 30, 2014

Debt Instrument [Line Items]

Schedule of Debt [Table Text Block]

DEBT OBLIGATIONS:

Our outstanding consolidated indebtedness was as follows:

	September 30, 2014		December 31, 2013
Parent Company Indebtedness:
ETE Senior Notes due October 15, 2020	$	1,187	$	1,187
ETE Senior Notes due January 15, 2024	1,150		450
ETE Senior Secured Term Loan due December 2, 2019	1,400		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	800		171
Subsidiary Indebtedness:
ETP Senior Notes	10,890		11,182
Regency Senior Notes	4,899		2,800
PVR Senior Notes	789		—
Transwestern Senior Notes	870		870
Panhandle Senior Notes	1,085		1,085
Sunoco Senior Notes	965		965
Sunoco Logistics Senior Notes	2,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	800		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	689		510
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	35		35
Sunoco Logistics $1.5 billion Revolving Credit Facility due November 19, 2018	525		200
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019	270		—
Other Long-Term Debt	220		228
Unamortized premiums, net of discounts and fair value adjustments	304		301
Total	29,853		23,199
Less: Current maturities of long-term debt	1,345		637
Long-term debt and notes payable, less current maturities	$	28,508	$	22,562

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Operations And Organization Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			50.00%
Trunkline LNG [Member]
LNG Storage Capacity	9.0		9.0
ETP [Member] | Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			70.00%
ETP [Member] | Susser [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
ETP [Member] | Sunoco LP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			44.00%
Fayetteville Express Pipeline, LLC [Member] | FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
FGT [Member] | FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Regency [Member] | Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			30.00%
Retail Marketing [Member]
Excise Taxes Collected	$ 632	$ 581	$ 1,740	$ 1,660

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Debt Obligations Debt Table (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Mar. 21, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Other Long-term Debt	$ 220		$ 228
Debt Instrument, Unamortized Discount (Premium), Net	304		301
Long-term Debt	29,853		23,199
Current maturities of long-term debt	1,345		637
LONG-TERM DEBT, less current maturities	28,508		22,562
Parent Company [Member]
Debt Instrument [Line Items]
LONG-TERM DEBT, less current maturities	4,540		2,801
Parent Company [Member] | ETE 7.5% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior Notes	1,187		1,187
Parent Company [Member] | 5.875% Senior Notes due January 15, 2024 [Member]
Debt Instrument [Line Items]
Senior Notes	1,150		450
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Secured Debt	1,400		1,000
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2018 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	800		171
ETP [Member]
Debt Instrument [Line Items]
Senior Notes	10,890		11,182
ETP [Member] | ETP Revolving Credit Facility, due October 2017 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	800		65
Regency [Member]
Debt Instrument [Line Items]
Senior Notes	4,899		2,800
Regency [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	689		510
PVR [Member]
Debt Instrument [Line Items]
Senior Notes	789	1,200	0
Transwestern [Member]
Debt Instrument [Line Items]
Senior Notes	870		870
Panhandle [Member]
Debt Instrument [Line Items]
Senior Notes	1,085		1,085
Sunoco [Member]
Debt Instrument [Line Items]
Senior Notes	965		965
Sunoco Logistics [Member]
Debt Instrument [Line Items]
Senior Notes	2,975		2,150
Sunoco Logistics [Member] | Sunoco Logistics $35 million Revolving Credit Facility, due April 30, 2015 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	35		35
Sunoco Logistics [Member] | Sunoco Logistics Revolving Credit Facility due November 19, 2018 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	525		200
Sunoco LP [Member] | Sunoco LP $250 Million Revolving Credit Facility Due September 2017 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 270		$ 0

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Other Information Table - Other Current Assets (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Other Information [Abstract]
Deposits paid to vendors	$ 46	$ 49
Prepaid expenses and other	261	263
Total other current assets	$ 307	$ 312

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
ASSETS
Cash and cash equivalents	$ 1,108	$ 590
Accounts receivable, net	4,722	3,658
Accounts receivable from related companies	51	63
Inventories	1,780	1,807
Exchanges receivable	58	67
Price risk management assets	16	39
Other current assets	307	312
Total current assets	8,042	6,536
PROPERTY, PLANT AND EQUIPMENT	43,017	33,917
ACCUMULATED DEPRECIATION	(4,280)	(3,235)
PROPERTY, PLANT AND EQUIPMENT, net	38,737	30,682
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,633	4,014
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	1	18
GOODWILL	7,867	5,894
INTANGIBLE ASSETS, net	5,504	2,264
OTHER NON-CURRENT ASSETS, net	897	922
Total assets	64,681	50,330
LIABILITIES AND EQUITY
Accounts payable	4,694	3,834
Accounts payable to related companies	6	14
Exchanges payable	269	284
Price risk management liabilities	9	53
Accrued and other current liabilities	2,108	1,678
Current maturities of long-term debt	1,345	637
Total current liabilities	8,431	6,500
LONG-TERM DEBT, less current maturities	28,508	22,562
DEFERRED INCOME TAXES	4,230	3,865
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	112	73
OTHER NON-CURRENT LIABILITIES	1,060	1,019
COMMITMENTS AND CONTINGENCIES (Note 13)
PREFERRED UNITS OF SUBSIDIARY	32	32
REDEEMABLE NONCONTROLLING INTEREST	15	0
EQUITY:
General Partner	(1)	(3)
Limited Partners:
Common Unitholders	687	1,066
Class D Units	18	6
Accumulated other comprehensive income	5	9
Total partners’ capital	709	1,078
Noncontrolling interest	21,584	15,201
Total equity	22,293	16,279
Total liabilities and equity	$ 64,681	$ 50,330

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Advances to and Investments in Unconsolidated Affiliates Table - Selected I/S Data (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Schedule of Equity Method Investments [Line Items]
Revenue	$ 919	$ 883	$ 3,703	$ 3,324
Operating income	206	196	881	839
Net income	$ 82	$ 64	$ 505	$ 460

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Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 1,418	$ 1,016
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,248	962
Deferred income taxes	(66)	244
Amortization included in interest expense	(41)	(43)
Non-cash compensation expense	60	43
Gain on sale of AmeriGas common units	(177)	(87)
Losses on disposal of assets	13	0
Gains (losses) on extinguishment of debt	(2)	7
LIFO valuation adjustments	17	(22)
Equity in earnings of unconsolidated affiliates	(265)	(182)
Distributions from unconsolidated affiliates	224	269
Other non-cash	(42)	22
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation	120	(382)
Net cash provided by operating activities	2,507	1,847
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(1,794)	(5)
Cash proceeds from the sale of AmeriGas common units	814	346
Capital expenditures (excluding allowance for equity funds used during construction)	(3,714)	(2,504)
Contributions in aid of construction costs	34	11
Contributions to unconsolidated affiliates	(264)	(3)
Distributions from unconsolidated affiliates in excess of cumulative earnings	97	326
Proceeds from sale of discontinued operations	79	973
Proceeds from the sale of assets	22	72
Increase (Decrease) in Restricted Cash	162	0
Other	(10)	(49)
Net cash used in investing activities	(4,574)	(833)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	12,044	9,768
Repayments of long-term debt	(8,342)	(9,439)
Subsidiary equity offerings, net of issue costs	1,881	1,450
Distributions to partners	(596)	(544)
Debt issuance costs	(61)	(56)
Distributions to noncontrolling interest	(1,359)	(1,050)
Capital contributions received from noncontrolling interest	19	15
Redemption of Preferred Units	0	(340)
Units repurchased under buyback program	(1,000)	0
Other, net	(1)	(13)
Net cash provided by (used in) financing activities	2,585	(209)
INCREASE IN CASH AND CASH EQUIVALENTS	518	805
CASH AND CASH EQUIVALENTS, beginning of period	590	372
CASH AND CASH EQUIVALENTS, end of period	$ 1,108	$ 1,177

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Lake Charles LNG [Member]
Incremental Income Tax Related to Transaction	$ 87
Susser Merger [Member]
Deferred Tax Liabilities, Other	$ 457

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

9 Months Ended

Sep. 30, 2014

Environmental Exit Cost [Line Items]

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 2056.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Rental expense(1)	$	31		$	33		$	90		$	98
Less: Sublease rental income	(9		)	(6		)	(27		)	(16		)
Rental expense, net	$	22		$	27		$	63		$	82

⁽¹⁾  Includes contingent rentals totaling $8 million for the three months ended September 30,2014 and 2013, and $17 million and $18 million for the nine months ended September 30,2014 and 2013, respectively.

Environmental Exit Costs by Cost

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

	September 30, 2014		December 31, 2013
Current	$	73	$	47
Non-current	321		356
Total environmental liabilities	$	394	$	403

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Price Risk Management Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014 barrels	Dec. 31, 2013 barrels
Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]
Notional Volume	(81,000)	103,000
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Call Option [Member] | ETP [Member]
Notional Volume	54,400	103,200
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	343,775	351,050
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Future [Member] | ETP [Member]
Notional Volume	(57,744)	(772,476)
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Options - Puts [Member] | ETP [Member]
Notional Volume	(54,400)	(52,800)
Maximum Term Of Commodity Derivatives	2014	2014
Cash Flow Hedging [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]
Notional Volume	0	(30,000)
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Future [Member]
Notional Volume	(243,000)	(280,000)
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	2,882,500	(487,500)
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Notional Volume	0	1,937,500
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	920,000	9,457,500
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Options - Puts [Member] | ETP [Member]
Notional Volume	5,000,000	0
Maximum Term Of Commodity Derivatives	2015
Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015	2017
Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives		2016
Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015	2019
Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives		2014
Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	(1,602,800)	(1,133,600)
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	(1,715,000)	(521,000)
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas Liquids [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	(439,000)	(438,000)
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Future [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(7,182,500)	570,000
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Notional Volume	17,790,000	(9,690,000)
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(8,067,500)	(8,195,000)
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Notional Volume	(13,289,000)	(24,455,000)
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member]
Notional Volume	(9,325,164)	5,668,559
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	(44,562,000)	(52,122,000)
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2016
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas Liquids [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives		2016
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2019	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2015	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2015	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas Liquids [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(24,197,500)	(7,352,500)
Maximum Term Of Commodity Derivatives	2015	2014
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(24,197,500)	(50,530,000)
Maximum Term Of Commodity Derivatives	2015	2014
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | ETP [Member]
Notional Volume	24,197,500	50,530,000
Maximum Term Of Commodity Derivatives	2015	2014
Non Trading [Member] | Cash Flow Hedging [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	(255,000)	(780,000)
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(460,000)	(1,825,000)
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(3,220,000)	(12,775,000)
Maximum Term Of Commodity Derivatives	2014	2014

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Other Information

9 Months Ended

Sep. 30, 2014

Other Information [Abstract]

Other Information

OTHER INFORMATION:

The tables below present additional detail for certain balance sheet captions.

Other Current Assets

Other current assets consisted of the following:

	September 30, 2014		December 31, 2013
Deposits paid to vendors	$	46	$	49
Prepaid expenses and other	261		263
Total other current assets	$	307	$	312

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	September 30, 2014		December 31, 2013
Interest payable	$	410	$	357
Customer advances and deposits	95		142
Accrued capital expenditures	398		260
Accrued wages and benefits	204		173
Taxes payable other than income taxes	343		211
Income taxes payable	127		4
Deferred income taxes	132		119
Other	399		412
Total accrued and other current liabilities	$	2,108	$	1,678

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Price Risk Management Assets And Liabilities (Tables)

9 Months Ended

Sep. 30, 2014

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

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(4	)	$	(11	)	$	(2	)	$	(12	)
Commodity derivatives – Non-trading	Cost of products sold	52			(34		)	9			(20		)
Commodity derivatives – Non-trading	Deferred gas purchases	—			—			—			(3		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(25		)	3			(73		)	55
Embedded derivatives	Other income	(1		)	24			(11		)	2
Total		$	22		$	(18	)	$	(77	)	$	22

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
Entity	Term	Type(1)	September 30, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	—	$	400
ETP	July 2015(2)	Forward-starting to pay a fixed rate of 3.38% and receive a floating rate	200		—
ETP	July 2016(3)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	200		—
ETP	July 2017(4)	Forward-starting to pay a fixed rate of 4.18% and receive a floating rate	200		—
ETP	July 2018(4)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		—
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	—		600
ETP	June 2021	Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%	—		400
ETP	February 2023	Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%	200		400
Panhandle	November 2021	Pay a fixed rate of 3.82% and receive a floating rate	125		275

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

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

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Fair Value Of Derivative Instruments

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014			December 31, 2013
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	2	$	3	$	(3	)	$	(18	)
	2		3		(3		)	(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	114	$	227	$	(110	)	$	(209	)
Commodity derivatives	25		43		(16		)	(48		)
Interest rate derivatives	3		47		(86		)	(95		)
Embedded derivatives in Regency Preferred Units	—		—		(30		)	(19		)
	142		317		(242		)	(371		)
Total derivatives	$	144	$	320	$	(245	)	$	(389	)

Derivatives, Offsetting Fair Value Amounts [Table Text Block]

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

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2014			December 31, 2013			September 30, 2014			December 31, 2013
Derivatives in offsetting agreements:
OTC contracts	Price risk management asset (liability)	$	12		$	42		$	(12	)	$	(38	)
Broker cleared derivative contracts	Other current assets	130			264			(152		)	(318		)
		142			306			(164		)	(356		)
Offsetting agreements:
Counterparty netting	Price risk management asset (liability)	(9		)	(36		)	9			36
Payments on margin deposit	Other current assets	(5		)	(1		)	30			55
		(14		)	(37		)	39			91
Net derivatives with offsetting agreements		128			269			(125		)	(265		)
Derivatives without offsetting agreements		16			51			(120		)	(124		)
Total derivatives		$	144		$	320		$	(245	)	$	(389	)

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 September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	3	$	(4	)	$	(3	)	$	4
Total	$	3	$	(4	)	$	(3	)	$	4

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	—	$	3	$	(6	)	$	5
Total		$	—	$	3	$	(6	)	$	5

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

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014			2013
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	1	$	—	$	(5	)	$	4
Total		$	1	$	—	$	(5	)	$	4

ETP [Member]

Outstanding Commodity-Related Derivatives

The following table details ETP’s outstanding commodity-related derivatives:

	September 30, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	920,000		2014-2015	9,457,500		2014-2019
Basis Swaps IFERC/NYMEX (1)	2,882,500		2014-2015	(487,500	)	2014-2017
Options – Puts	5,000,000		2015	—		—
Swing Swaps	—		—	1,937,500		2014-2016
Power (Megawatt):
Forwards	343,775		2014	351,050		2014
Futures	(57,744	)	2014	(772,476	)	2014
Options — Puts	(54,400	)	2014	(52,800	)	2014
Options — Calls	54,400		2014	103,200		2014
Crude (Bbls) — Futures	(81,000	)	2014	103,000		2014
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(7,182,500	)	2014-2015	570,000		2014
Swing Swaps IFERC	17,790,000		2014	(9,690,000	)	2014-2016
Fixed Swaps/Futures	(8,067,500	)	2014-2019	(8,195,000	)	2014-2015
Forward Physical Contracts	(9,325,164	)	2014-2015	5,668,559		2014-2015
Natural Gas Liquid (Bbls) — Forwards/Swaps	(1,602,800	)	2014-2015	(1,133,600	)	2014
Refined Products (Bbls) — Futures	(243,000	)	2014-2015	(280,000	)	2014
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(24,197,500	)	2015	(7,352,500	)	2014
Fixed Swaps/Futures	(24,197,500	)	2015	(50,530,000	)	2014
Hedged Item — Inventory	24,197,500		2015	50,530,000		2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(460,000	)	2014	(1,825,000	)	2014
Fixed Swaps/Futures	(3,220,000	)	2014	(12,775,000	)	2014
Natural Gas Liquid (Bbls) — Forwards/Swaps	(255,000	)	2014	(780,000	)	2014
Crude (Bbls) — Futures	—		—	(30,000	)	2014

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

Regency [Member]

Outstanding Commodity-Related Derivatives

The following table details Regency’s outstanding commodity-related derivatives:

	September 30, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(13,289,000	)	2014-2015	(24,455,000	)	2014-2015
Propane (Gallons) — Forwards/Swaps	(44,562,000	)	2014-2015	(52,122,000	)	2014-2015
NGLs (Barrels) — Forwards/Swaps	(439,000	)	2014-2015	(438,000	)	2014
WTI Crude Oil (Barrels) — Forwards/Swaps	(1,715,000	)	2014-2016	(521,000	)	2014

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Supplemental Financial Statement Information

9 Months Ended

Sep. 30, 2014

Supplemental Financial Statement Information

Supplemental Financial Statement Information

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS

(unaudited)

	September 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9		$	8
Accounts receivable from related companies	13			5
Other current assets	1			—
Total current assets	23			13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	5,303			3,841
INTANGIBLE ASSETS, net	11			14
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	49			41
Total assets	$	5,395		$	3,918
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related companies	$	77		$	11
Interest payable	63			24
Accrued and other current liabilities	3			3
Total current liabilities	143			38
LONG-TERM DEBT, less current maturities	4,540			2,801
OTHER NON-CURRENT LIABILITIES	3			1
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	687			1,066
Class D Units	18			6
Accumulated other comprehensive income	5			9
Total partners’ capital	709			1,078
Total liabilities and partners’ capital	$	5,395		$	3,918

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(20	)	$	(11	)	$	(83	)	$	(40	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(57		)	(47		)	(147		)	(164		)
Gains on interest rate derivatives	—			3			—			9
Equity in earnings of unconsolidated affiliates	269			207			756			573
Other, net	(2		)	(1		)	(4		)	(11		)
INCOME BEFORE INCOME TAXES	190			151			522			367
Income tax expense (benefit)	2			—			2			(1		)
NET INCOME	188			151			520			368
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1			1			1
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	—			—			1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	188		$	150		$	518		$	367

STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended September 30,
	2014			2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	704		$	650
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds received in acquisitions and other transactions, net	—			1,332
Contributions to unconsolidated affiliate	(30		)	(8		)
Purchase of additional interest in Regency	(800		)	—
Payments received on note receivable from affiliate	—			166
Net cash used in investing activities	(830		)	1,490
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,820			440
Principal payments on debt	(1,082		)	(1,603		)
Distributions to partners	(596		)	(544		)
Redemption of Preferred Units	—			(340		)
Units repurchased under buyback program	(1,000		)	—
Debt issuance costs	(15		)	(2		)
Net cash used in financing activities	127			(2,049		)
INCREASE IN CASH AND CASH EQUIVALENTS	1			91
CASH AND CASH EQUIVALENTS, beginning of period	8			9
CASH AND CASH EQUIVALENTS, end of period	$	9		$	100

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Price Risk Management Assets And Liabilities Table - Gross FV and Netting Offset (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 144	$ 320
Derivative Liability, Fair Value, Gross Liability	(245)	(389)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(14)	(37)
Derivative Liability, Fair Value, Amount Offset Against Collateral	39	91
Netting [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	142	306
Derivative Liability, Fair Value, Gross Liability	(164)	(356)
Derivative Asset, Fair Value, Gross Liability	(9)	(36)
Derivative Liability, Fair Value, Gross Asset	9	36
Derivative Asset, Fair Value, Net	128	269
Derivative Liability, Fair Value, Net	(125)	(265)
Netting [Member] | OTC contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	42
Derivative Liability, Fair Value, Gross Liability	(12)	(38)
Netting [Member] | Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	130	264
Derivative Liability, Fair Value, Gross Liability	(152)	(318)
Netting [Member] | Asset Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Payments on Margin Deposits	(5)	(1)
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value	16	51
Netting [Member] | Liability Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Payments on Margin Deposits	30	55
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	$ (120)	$ (124)

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Operations And Organization

9 Months Ended

Sep. 30, 2014

Operations And Organization [Abstract]

Operations And Organization

OPERATIONS AND 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.

Our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names in September 2014 and October 2014, respectively, to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP, respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.

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

• the Parent Company;

• our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);

• ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDRs in ETP and Regency; and

• our wholly-owned subsidiary, Lake Charles LNG. Lake Charles LNG was acquired from ETP in February 2014.

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 Regency 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 18 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our activities are primarily conducted through our operating subsidiaries as follows:

• ETP is a publicly traded partnership whose operations are conducted through the following subsidiaries:

• ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through its Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.

• ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:

• Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.

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

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

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

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

• Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco. Panhandle and Sunoco operations are described as follows:

• Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 2, in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.

• Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and its wholly-owned subsidiary, Sunoco.

• Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.

• ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 44% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 2, in October 2014, Sunoco LP acquired MACS from ETP.

• Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading, and the management of coal and natural resource properties in the United States. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Its assets are primarily located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

• Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

Our financial statements reflect the following reportable business segments:

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

• Investment in Regency, including the consolidated operations of Regency.

• Investment in Lake Charles LNG, including the operations of Lake Charles LNG.

• 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.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2013, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of September 30, 2014 and for the three and nine months ended September 30, 2014 and 2013 have been prepared in accordance with GAAP for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of September 30, 2014, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2014 and 2013. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on February 27, 2014.

Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity.

We record the collection of taxes to be remitted to government authorities on a net basis except for ETP’s retail marketing operations, in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and cost of products sold in the consolidated statements of operations, with no net impact on net income. Excise taxes collected by ETP’s retail marketing operations were $632 million and $581 million for the three months ended September 30, 2014 and 2013, respectively, and $1.74 billion and $1.66 billion for the nine months endedSeptember 30, 2014 and 2013, respectively.

New 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. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. 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 April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.

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Consolidated Statements Of Operations (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
REVENUES:
Natural gas sales	$ 1,290	$ 915	$ 4,082	$ 2,752
NGL sales	1,797	968	4,451	2,468
Crude sales	4,497	4,215	13,022	11,408
Gathering, transportation and other fees	958	786	2,708	2,341
Refined product sales	5,165	4,633	14,581	13,945
Other	1,280	969	3,366	2,814
Total revenues	14,987	12,486	42,210	35,728
COSTS AND EXPENSES:
Cost of products sold	13,015	11,064	36,808	31,436
Operating expenses	540	419	1,359	1,178
Depreciation, depletion and amortization	425	332	1,248	962
Selling, general and administrative	185	142	490	448
Total costs and expenses	14,165	11,957	39,905	34,024
OPERATING INCOME	822	529	2,305	1,704
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(356)	(298)	(1,015)	(913)
Equity in earnings of unconsolidated affiliates	84	38	265	182
Gains (losses) on extinguishment of debt	2	0	2	(7)
Gains (losses) on interest rate derivatives	(25)	3	(73)	55
Gain on sale of AmeriGas common units	14	87	177	87
Other, net	(15)	33	(38)	0
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	526	392	1,623	1,108
Income tax expense from continuing operations	56	49	271	136
INCOME FROM CONTINUING OPERATIONS	470	343	1,352	972
Income from discontinued operations	0	13	66	44
NET INCOME	470	356	1,418	1,016
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	282	205	898	648
NET INCOME ATTRIBUTABLE TO PARTNERS	188	151	520	368
GENERAL PARTNER’S INTEREST IN NET INCOME	0	1	1	1
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	0	0	1	0
LIMITED PARTNERS’ INTEREST IN NET INCOME	$ 188	$ 150	$ 518	$ 367
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$ 0.35	$ 0.26	$ 0.94	$ 0.62
Diluted	$ 0.35	$ 0.26	$ 0.93	$ 0.62
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$ 0.35	$ 0.27	$ 0.95	$ 0.65
Diluted	$ 0.35	$ 0.27	$ 0.94	$ 0.65

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Income Taxes (Notes)

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES:

Income tax expense from continuing operations for the nine months ended September 30, 2014 included the impact of the Lake Charles LNG Transaction, which was treated as a sale for tax purposes, resulting in $87 million of incremental income tax expense.

The acquisition of Susser by ETP (see Note 2) on August 29, 2014 did not have a material impact on income tax expense or the effective rate for the third quarter of 2014 due to the timing of the acquisition. However, the acquisition of Susser is expected to increase the effective rate for the full year of 2014. Additionally, deferred tax liabilities increased by approximately $457 million as a result of the acquisition.

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DEI Document	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		538,766,899

XML

Retirement Benefits

9 Months Ended

Sep. 30, 2014

BENEFITS [Abstract]

Postemployment Benefits Disclosure [Text Block]

RETIREMENT BENEFITS:

The following table sets forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans:

	Three Months Ended September 30,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—		$	—		$	—		$	(1	)
Interest cost	8			1			10			2
Expected return on plan assets	(10		)	(2		)	(15		)	(3		)
Prior service cost amortization	—			—			—			1
Actuarial loss amortization	—			—			1			—
Settlement credits	(1		)	—			—			—
	(3		)	(1		)	(4		)	(1		)
Regulatory adjustment	—			—			1			—
Net periodic benefit cost	$	(3	)	$	(1	)	$	(3	)	$	(1	)

	Nine Months Ended September 30,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	1		$	—		$	5		$	—
Interest cost	23			4			28			5
Expected return on plan assets	(30		)	(6		)	(45		)	(7		)
Prior service cost amortization	—			—			—			1
Actuarial (gain) loss amortization	(1		)	—			2			—
Settlement credits	(3		)	—			(2		)	—
	(10		)	(2		)	(12		)	(1		)
Regulatory adjustment	—			—			5			—
Net periodic benefit cost	$	(10	)	$	(2	)	$	(7	)	$	(1	)

Panhandle has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and reflected in expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

Panhandle no longer has pension plans after the sale of the assets of Missouri Gas Energy and New England Gas Company in 2013.

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Supplemental Financial Statement Information Schedule of Statements of Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$ (185)	$ (142)	$ (490)	$ (448)
Interest Expense, net of interest capitalized	(356)	(298)	(1,015)	(913)
Equity in earnings of unconsolidated affiliates	84	38	265	182
Gains on interest rate derivatives	(25)	3	(73)	55
Other, net	(15)	33	(38)	0
Income tax expense (benefit)	56	49	271	136
NET INCOME ATTRIBUTABLE TO PARTNERS	188	151	520	368
GENERAL PARTNER’S INTEREST IN NET INCOME	0	1	1	1
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	0	0	1	0
LIMITED PARTNERS' INTEREST IN NET INCOME	188	150	518	367
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	(20)	(11)	(83)	(40)
Interest Expense, net of interest capitalized	(57)	(47)	(147)	(164)
Equity in earnings of unconsolidated affiliates	269	207	756	573
Gains on interest rate derivatives	0	3	0	9
Other, net	(2)	(1)	(4)	(11)
INCOME BEFORE INCOME TAXES	190	151	522	367
Income tax expense (benefit)	2	0	2	(1)
NET INCOME ATTRIBUTABLE TO PARTNERS	188	151	520	368
GENERAL PARTNER’S INTEREST IN NET INCOME	0	1	1	1
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	0	0	1	0
LIMITED PARTNERS' INTEREST IN NET INCOME	$ 188	$ 150	$ 518	$ 367

XML

Consolidated Statements Of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 470	$ 356	$ 1,418	$ 1,016
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	0	(3)	6	(5)
Change in value of derivative instruments accounted for as cash flow hedges	3	(4)	(3)	4
Change in value of available-for-sale securities	1	1	1	1
Actuarial gain (loss) relating to pension and other postretirement benefits	(1)	8	(2)	9
Foreign currency translation adjustments	(1)	0	(3)	(1)
Change in other comprehensive income from unconsolidated affiliates	0	9	(6)	13
Other comprehensive income (loss), net of tax	2	11	(7)	21
Comprehensive income	472	367	1,411	1,037
Less: Comprehensive income attributable to noncontrolling interest	285	213	895	660
Comprehensive income attributable to partners	$ 187	$ 154	$ 516	$ 377

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Fair Value Measurements [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS:

We have commodity derivatives, interest rate derivatives and embedded derivatives in the Regency 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 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, and we discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency 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 nine months endedSeptember 30, 2014, no transfers were made between any levels within the fair value hierarchy.

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 of our consolidated debt obligations as of September 30, 2014 and December 31, 2013 was $31.23 billion and $23.97 billion, respectively. As of September 30, 2014 and December 31, 2013, the aggregate carrying amount of our consolidated debt obligations was $29.85 billion and $23.20 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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 September 30, 2014 and December 31, 2013 based on inputs used to derive their fair values:

	Fair Value Measurements at September 30, 2014
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	3		$	—		$	3		$	—
Commodity derivatives:
Condensate — Forward Swaps	4			—			4			—
Natural Gas:
Basis Swaps IFERC/NYMEX	6			6			—			—
Swing Swaps IFERC	6			1			5			—
Fixed Swaps/Futures	75			69			6			—
Forward Physical Swaps	1			—			1			—
Natural Gas Liquids — Forwards/Swaps	16			13			3			—
Power:
Forwards	2			—			2			—
Futures	1			1			—			—
Refined Products — Futures	19			19			—			—
Total commodity derivatives	130			109			21			—
Total assets	$	133		$	109		$	24		$	—
Liabilities:
Interest rate derivatives	$	(86	)	$	—		$	(86	)	$	—
Embedded derivatives in the Regency Preferred Units	(30		)	—			—			(30		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(8		)	(8		)	—			—
Swing Swaps IFERC	(5		)	(1		)	(4		)	—
Fixed Swaps/Futures	(75		)	(73		)	(2		)	—
Forward Physical Swaps	(1		)	—			(1		)	—
Natural Gas Liquids — Forwards/Swaps	(19		)	(18		)	(1		)	—
Power:
Forwards	(2		)	—			(2		)	—
Futures	(2		)	(2		)	—			—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(118		)	(107		)	(11		)	—
Total liabilities	$	(234	)	$	(107	)	$	(97	)	$	(30	)

	Fair Value Measurements at December 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	47		$	—		$	47		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	8			1			7			—
Fixed Swaps/Futures	203			201			2			—
NGLs — Swaps	7			5			2			—
Power — Forwards	3			—			3			—
Refined Products — Futures	5			5			—			—
Total commodity derivatives	231			217			14			—
Total Assets	$	278		$	217		$	61		$	—
Liabilities:
Interest rate derivatives	$	(95	)	$	—		$	(95	)	$	—
Embedded derivatives in the Regency Preferred Units	(19		)	—			—			(19		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)	(4		)	—			—
Swing Swaps IFERC	(6		)	—			(6		)	—
Fixed Swaps/Futures	(206		)	(201		)	(5		)	—
Forward Physical Contracts	(1		)	—			(1		)	—
NGLs — Swaps	(9		)	(5		)	(4		)	—
Power — Forwards	(1		)	—			(1		)	—
Refined Products — Futures	(5		)	(5		)	—			—
Total commodity derivatives	(233		)	(215		)	(18		)	—
Total Liabilities	$	(347	)	$	(215	)	$	(113	)	$	(19	)

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 nine months endedSeptember 30, 2014.

Balance, December 31, 2013	$	(19	)
Net unrealized loss included in other income (expense)	(11		)
Balance, September 30, 2014	$	(30	)

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Inventories (Notes)

9 Months Ended

Sep. 30, 2014

Inventory, Net [Abstract]

Inventories

INVENTORIES:

Inventories consisted of the following:

	September 30, 2014		December 31, 2013
Natural gas and NGLs	$	404	$	523
Crude oil	459		488
Refined products	597		597
Appliances, parts and fittings and other	320		199
Total inventories	$	1,780	$	1,807

ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

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Reportable Segments

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

As a result of the Lake Charles LNG Transaction in 2014, our reportable segments were re-evaluated and currently reflect the following reportable segments:

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

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

• 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.

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, loss on extinguishment 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.

Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.

Eliminations in the tables below include the following:

• ETP’s Segment Adjusted EBITDA reflected 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA included its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star were included in eliminations.

• ETP’s Segment Adjusted EBITDA reflected the results of SUGS from March 26, 2012 to April 30, 2013. Since the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also included the results of SUGS from March 26, 2012 to April 30, 2013.

• ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the three and nine months ended September 30, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013.

The following tables present financial information by segment:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Segment Adjusted EBITDA:
Investment in ETP	$	1,172		$	942		$	3,547		$	2,967
Investment in Regency	344			172			856			446
Investment in Lake Charles LNG	51			47			146			139
Corporate and Other	(18		)	(9		)	(73		)	(38		)
Adjustments and Eliminations	(78		)	(103		)	(190		)	(250		)
Total	1,471			1,049			4,286			3,264
Depreciation, depletion and amortization	(425		)	(332		)	(1,248		)	(962		)
Interest expense, net of interest capitalized	(356		)	(298		)	(1,015		)	(913		)
Gain on sale of AmeriGas common units	14			87			177			87
Gains (losses) on interest rate derivatives	(25		)	3			(73		)	55
Non-cash unit-based compensation expense	(20		)	(16		)	(60		)	(43		)
Unrealized gains (losses) on commodity risk management activities	32			22			(11		)	45
Gains (losses) on extinguishment of debt	2			—			2			(7		)
LIFO valuation adjustments	(51		)	6			(17		)	22
Equity in earnings of unconsolidated affiliates	84			38			265			182
Adjusted EBITDA related to unconsolidated affiliates	(183		)	(165		)	(583		)	(553		)
Adjusted EBITDA related to discontinued operations	—			(12		)	(27		)	(75		)
Other, net	(17		)	10			(73		)	6
Income from continuing operations before income tax expense	$	526		$	392		$	1,623		$	1,108

	September 30, 2014			December 31, 2013
Total assets:
Investment in ETP	$	48,571		$	43,702
Investment in Regency	17,180			8,782
Investment in Lake Charles LNG	1,170			1,338
Corporate and Other	804			720
Adjustments and Eliminations	(3,044		)	(4,212		)
Total	$	64,681		$	50,330

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues:
Investment in ETP:
Revenues from external customers	$	13,573		$	11,848		$	38,778		$	34,214
Intersegment revenues	45			54			101			93
	13,618			11,902			38,879			34,307
Investment in Regency:
Revenues from external customers	1,381			633			3,282			1,796
Intersegment revenues	102			32			242			48
	1,483			665			3,524			1,844
Investment in Lake Charles LNG:
Revenues from external customers	55			55			162			162
Adjustments and Eliminations	(169		)	(136		)	(355		)	(585		)
Total revenues	$	14,987		$	12,486		$	42,210		$	35,728

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

Investment in ETP

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Intrastate Transportation and Storage	$	559	$	502	$	2,075	$	1,705
Interstate Transportation and Storage	254		296		794		973
Midstream	311		334		915		973
Liquids Transportation and Services	1,165		537		2,844		1,303
Investment in Sunoco Logistics	4,862		4,502		14,080		12,215
Retail Marketing	5,985		5,297		16,561		15,805
All Other	482		434		1,610		1,333
Total revenues	13,618		11,902		38,879		34,307
Less: Intersegment revenues	45		54		101		93
Revenues from external customers	$	13,573	$	11,848	$	38,778	$	34,214

Investment in Regency

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Gathering and Processing	$	1,387	$	603	$	3,254	$	1,671
Contract Services	76		58		217		159
Natural Resources	18		—		40		—
Corporate and Other	2		4		13		14
Total revenues	1,483		665		3,524		1,844
Less: Intersegment revenues	102		32		242		48
Revenues from external customers	$	1,381	$	633	$	3,282	$	1,796

Investment in Lake Charles LNG

Lake Charles LNG’s revenues of $55 million and $162 million for the three and nine months ended September 30, 2014, respectively, and $55 million and $162 million for the three and nine months ended September 30, 2013, respectively, were related to LNG terminalling.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

9 Months Ended

Sep. 30, 2014

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus

Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.

On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.

FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.

Contingent Residual Support Agreement — AmeriGas

In connection with the closing of the contribution of ETP’s propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of senior notes issued by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases.

PEPL Holdings Guarantee of Collection

In connection with the SUGS Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023(the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.

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.

Transwestern Rate Case

On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to a 2011 settlement agreement with its shippers.  Transwestern expects the FERC to set a procedural schedule with a hearing scheduled in late 2015 for this case.

FGT Rate Case

On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. FGT expects the FERC to set a procedural schedule with a hearing scheduled in late 2015 for this case.

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 2056.  The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Rental expense(1)	$	31		$	33		$	90		$	98
Less: Sublease rental income	(9		)	(6		)	(27		)	(16		)
Rental expense, net	$	22		$	27		$	63		$	82

⁽¹⁾  Includes contingent rentals totaling $8 million for the three months ended September 30,2014 and 2013, and $17 million and $18 million for the nine months ended September 30,2014 and 2013, 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.

MTBE Litigation

Sunoco, 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 are asserting primarily 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 are seeking to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As of September 30, 2014, Sunoco is a defendant in nine cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of 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. Six of these cases are venued in a multidistrict litigation (“MDL”) proceeding in a New York federal court. The most recently filed Puerto Rico action is expected to be transferred to the MDL. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.

Fact discovery has concluded with respect to an initial set of fewer than 20 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco in these matters. 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.

Litigation Relating to the PVR Merger

Five putative class action lawsuits challenging the merger have been filed and are currently pending. All of the cases name PVR, PVR GP and the current directors of PVR GP, as well as Regency and the General Partner of Regency (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of their fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly caused by the defendants to these actions, and, (vi) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. (Case No. 9015-VCL) in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606) and Saul Srour v. PVR Partners, L.P., et al. (Case No. 2013-011015), each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-06829-HB); and Mark Hinnau v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-07496-HB), pending in the United States District Court for the Eastern District of Pennsylvania.

On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, which occurred on March 21, 2014, completion of certain confirmatory discovery, class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.

The settlement will not affect any provisions of the merger agreement or the form or amount of consideration received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.

Utility Line Services, Inc. v. PVR Marcellus Gas Gathering LLC

On May 22, 2012, Plaintiff and Counterclaim Defendant, Utility Line Services, Inc. (“ULS”) filed suit against PVR Marcellus Gas Gathering, LLC now known as Regency Marcellus Gas Gathering LLC (“Regency Marcellus”) relating to a dispute involving payment under a construction contract (the “Construction Contract”) entered into in October 2010 for Regency Marcellus’ multi-phase pipeline construction project in Lycoming County, PA (the “Project”). Under the terms of the Construction Contract, Regency Marcellus believed ULS was obligated to design, permit and build Phases I and II of Regency Marcellus’ 30-inch pipeline and to design additional phases of the project.Due to ULS’ deficiencies and delays throughout the project, as well as extensive overbilling for its services, Regency Marcellus allowed the Construction Contractto terminate in accordance with its terms in December 2011 and refused to pay ULS’ outstanding invoices for the Project. ULS then filed suit alleging: Regency Marcellus’ refusal to pay certain invoices totaling approximately $17 million; penalties pursuant to the Pennsylvania Contractor and Subcontractor Payment Act, 73 P.S. § 501, et seq. (“CASPA”), Regency Marcellus’ alleged wrongful withholding of payments owed to ULS; and breach of contract in connection with Regency Marcellus’ alleged wrongful termination of ULS in December 2011.  ULS alleged damages, inclusive of CASPA penalties, are in excess of $30 million. Regency Marcellus alleged counterclaims against ULS for breach of the parties’ contract for engineering and construction services; restitution for Regency Marcellus’ overpayments to ULS because of ULS’ improper billing practices; attorneys’ fees resulting from ULS’ meritless claim under CASPA; and professional malpractice against ULS for negligent performance of various engineering services on the Project. Regency Marcellus’ alleged damages exceed $21 million.

Trial commenced on March 24, 2014 and on April 17, 2014, the jury found in favor of ULS and assessed damages against Regency Marcellus of approximately $24 million plus interest and penalties. In June 2014, ULS and Regency Marcellus reached a settlement in this matter, the terms of which are confidential. The settlement will not have a material adverse effect on Regency’s business or financial position.

Litigation Related to the Eagle Rock Midstream Acquisition

Three putative class action lawsuits challenging Regency’s acquisition of the Eagle Rock midstream assets are currently pending in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as Regency and a subsidiary as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction, claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. Regency and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board.

Other Litigation and Contingencies

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of September 30, 2014 and December 31, 2013, accruals of approximately $42 million and $46 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 September 30, 2014 or December 31, 2013 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 $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, Southern Union’s 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.

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 retail sites.

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

• Sunoco 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 September 30, 2014, Sunoco had been named as a PRP at approximately 49 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law.  Sunoco is usually one of a number of companies identified as a PRP at a site.  Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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

	September 30, 2014		December 31, 2013
Current	$	73	$	47
Non-current	321		356
Total environmental liabilities	$	394	$	403

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

During the three months ended September 30, 2014 and 2013, the Partnership recorded $10 million and $9 million, respectively, of expenditures related to environmental cleanup programs. During the nine months endedSeptember 30, 2014 and 2013, the Partnership recorded $27 million of expenditures related to environmental cleanup programs.

On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines.  The rule became effective on August 29, 2011.  The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future.  At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.

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.

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.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the New Mexico Environmental Department (“NMED”) and the Texas Commission on Environmental Quality (“TCEQ”). The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three SUGS recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.

Compliance Orders from the New Mexico Environmental Department. SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until October 2014 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

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Redeemable Noncontrolling Interest (Notes)

9 Months Ended

Sep. 30, 2014

Redeemable Noncontrolling Interest [Table Text Block]

REDEEMABLE NONCONTROLLING INTERESTS:

The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet as of September 30, 2014.

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Retirement Benefits Table - Components of Pension Expense (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 0	$ 0	$ 1	$ 5
Interest cost	8	10	23	28
Expected return on plan assets	(10)	(15)	(30)	(45)
Prior service cost amortization	0	0	0	0
Actuarial loss amortization	0	(1)	1	(2)
Settlement credits	(1)	0	(3)	(2)
Net periodic benefit cost subtotal	(3)	(4)	(10)	(12)
Regulatory adjustment	0	1	0	5
Net periodic benefit cost	(3)	(3)	(10)	(7)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	(1)	0	0
Interest cost	1	2	4	5
Expected return on plan assets	(2)	(3)	(6)	(7)
Prior service cost amortization	0	1	0	1
Actuarial loss amortization	0	0	0	0
Settlement credits	0	0	0	0
Net periodic benefit cost subtotal	(1)	(1)	(2)	(1)
Regulatory adjustment	0	0	0	0
Net periodic benefit cost	$ (1)	$ (1)	$ (2)	$ (1)

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Net Income per Limited Partner Unit

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Net Income Per Limited Partner Unit

NET INCOME PER LIMITED PARTNER UNIT:

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
Income from continuing operations	$	470		$	343	$	1,352		$	972
Less: Income from continuing operations attributable to noncontrolling interest	282			195		839			623
Income from continuing operations, net of noncontrolling interest	188			148		513			349
Less: General Partner’s interest in income from continuing operations	—			1		1			1
Less: Class D Unitholder’s interest in income from continuing operations	—			—		1			—
Income from continuing operations available to Limited Partners	$	188		$	147	$	511		$	348
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	538.8			561.4		546.6			560.8
Basic income from continuing operations per Limited Partner unit	$	0.35		$	0.26	$	0.94		$	0.62
Basic income from discontinued operations per Limited Partner unit	$	—		$	0.01	$	0.01		$	0.03
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	188		$	147	$	511		$	348
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1		)	—		(2		)	(1		)
Diluted income from continuing operations available to Limited Partners	$	187		$	147	$	509		$	347
Weighted average limited partner units	538.8			561.4		546.6			560.8
Dilutive effect of unconverted unit awards	1.1			—		1.0			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	539.9			561.4		547.6			560.8
Diluted income from continuing operations per Limited Partner unit	$	0.35		$	0.26	$	0.93		$	0.62
Diluted income from discontinued operations per Limited Partner unit	$	—		$	0.01	$	0.01		$	0.03

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Debt Obligations

9 Months Ended

Sep. 30, 2014

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

Our outstanding consolidated indebtedness was as follows:

	September 30, 2014		December 31, 2013
Parent Company Indebtedness:
ETE Senior Notes due October 15, 2020	$	1,187	$	1,187
ETE Senior Notes due January 15, 2024	1,150		450
ETE Senior Secured Term Loan due December 2, 2019	1,400		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	800		171
Subsidiary Indebtedness:
ETP Senior Notes	10,890		11,182
Regency Senior Notes	4,899		2,800
PVR Senior Notes	789		—
Transwestern Senior Notes	870		870
Panhandle Senior Notes	1,085		1,085
Sunoco Senior Notes	965		965
Sunoco Logistics Senior Notes	2,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	800		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	689		510
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015	35		35
Sunoco Logistics $1.5 billion Revolving Credit Facility due November 19, 2018	525		200
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019	270		—
Other Long-Term Debt	220		228
Unamortized premiums, net of discounts and fair value adjustments	304		301
Total	29,853		23,199
Less: Current maturities of long-term debt	1,345		637
Long-term debt and notes payable, less current maturities	$	28,508	$	22,562

Parent Company Indebtedness

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

ETE Term Loan Facility

In April 2014, the Parent Company amended its Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”) to increase the aggregate principal amount to $1.4 billion. The Parent Company used the proceeds from this $400 million increase to repay borrowings under its revolving credit facility and for general partnership purposes. No other significant changes were made to the terms of the ETE Term Credit Agreement, including maturity date and interest rate.

Revolving Credit Facility

In May 2014, the Parent Company amended its revolving credit facility to increase the capacity to $1.2 billion. As of September 30, 2014, there were $800 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $400 million.

Senior Notes

In May 2014, the Parent Company issued an additional $700 million in principal amount of its 5.875% senior notes due 2024 in a private placement and used the net proceeds to repay amounts outstanding under its revolving credit facility and for general partnership purposes.

The Parent Company currently has outstanding an aggregate of $1.19 billion in principal amount of 7.5% senior notes due 2020 and $1.15 billion in principal amount of 5.875% senior notes due 2024.

Sunoco Logistics Senior Notes

In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044. The net proceeds from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facility and for general partnership purposes.

Regency Senior Notes

In February 2014, Regency issued $900 million aggregate principal amount of 5.875% senior notes due March 1, 2022.

In March 2014, as part of the PVR Acquisition, Regency assumed the outstanding senior notes of PVR with an aggregate notional amount of $1.2 billion. The PVR senior notes consisted of $300 million principal amount of 8.25% senior notes due April 15, 2018, $400 million principal amount of 6.5% senior notes due May 15, 2021, and $473 million principal amount of 8.375% senior notes due June 1, 2020. In April 2014, Regency redeemed all of the $300 million principal amount of 8.25% senior notes due April 15, 2018 for $313 million in cash. In July 2014, Regency redeemed $83 million of the $473 million principal amount of 8.375% senior notes due June 1, 2020 for $91 million, including $8 million of accrued interest and redemption premium.

In July 2014, Regency exchanged $499 million aggregate principal amount of 8.375% senior notes due 2019 of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% Senior Notes due 2019 issued by Regency and its wholly-owned subsidiary.

In July 2014, Regency issued $700 million aggregate principal amount of 5.0% senior notes that mature on October 1, 2022.

In October 2014, Regency issued a notice of redemption to the holders of the $600 million6.875% senior notes due December 1, 2018, with a redemption date of December 2, 2014 for a total price of 103.438%.

Subsidiary Credit Facilities

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2017. 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 ETP’s current and future unsecured debt. As of September 30, 2014, the ETP Credit Facility had $800 million of outstanding borrowings.

Regency Credit Facility

In February 2014, Regency entered into an amendment to the Regency Credit Facility to increase the borrowing capacity of the Regency Credit Facility to $1.5 billion with a $500 million uncommitted incremental facility and extended the maturity date to May 21, 2018. In September 2014, Regency entered into an amendment to, among other things, increase the letter of credit sublimit from $50 million to $100 million and update various swap agreement provisions to conform to current market standards. As of September 30, 2014, the Regency Credit Facility had a balance outstanding of $689 million in outstanding borrowings and approximately $25 million in letters of credit.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $1.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $2.25 billion under certain conditions. As of September 30, 2014, the Sunoco Logistics Credit Facility had $525 million of outstanding borrowings.

Sunoco LP Credit Facility

On September 25, 2014, Sunoco LP entered into a $1.25 billion revolving credit agreement (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 September 30, 2014, the Sunoco LP Credit Facility had $270 million of outstanding borrowings.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2014.

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Equity

9 Months Ended

Sep. 30, 2014

Partners' Capital Notes [Abstract]

Equity

EQUITY:

ETE Common Unit Activity

The change in ETE Common Units during the nine months ended September 30, 2014 was as follows:

	Number of Units
Outstanding at December 31, 2013	559.9
Repurchase of units under buyback program	(21.1	)
Outstanding at September 30, 2014	538.8

From January through May, ETE repurchased approximately $1 billion of ETE common units, completing its buyback program.

Sales of Common Units by Subsidiaries

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

As a result of ETP’s and Regency’s issuances of common units during the nine months endedSeptember 30, 2014, we recognized increases in partners’ capital of $702 million.

Sales of Common Units by ETP

During thenine months ended September 30,2014, ETP received proceeds of$1.03 billion, net of commissions of$11 million, from the issuance of units pursuant to equity distribution agreements, which proceeds were used for general partnership purposes. As ofSeptember 30, 2014, approximately$109 million of ETP Common Units remained available to be issued under an equity distribution agreement, and all of the remaining capacity was utilized in October 2014.

During the nine months ended September 30,2014, distributions of $100 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 1.9 million ETP Common Units. As of September 30, 2014, a total of 0.2 million ETP Common Units remain available to be issued under the existing registration statement.

In October 2014, ETP filed a new registration statement with the SEC covering the issuance of up to an additional 8 million ETP Common Units under the Distribution Reinvestment Plan.

Sales of Common Units by Regency

For the nine months ended September 30,2014, Regency received proceeds of $162 million, net of commissions of approximately $2 million, from units issued pursuant to its equity distribution agreements, which proceeds were used for general partnership purposes. As of September 30, 2014, approximately $272 million remained available to be issued under the agreement.

Regency issued 4.0 million, 140.4 million and 8.2 million Regency Common Units in connection with the Hoover, PVR and Eagle Rock Midstream acquisitions, respectively.

In June 2014, Regency sold 14.4 million Regency Common Units to a wholly-owned subsidiary of ETE for approximately $400 million. In July 2014, Regency sold an additional 16.5 million Regency Common Units to a wholly-owned subsidiary of ETE in connection with the Eagle Rock Midstream Acquisition for approximately $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition.

Sales of Common Units by Sunoco Logistics

In May 2014, Sunoco Logistics entered into an equity distribution agreement pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $250 million. During the nine months ended September 30,2014, Sunoco Logistics received proceeds of $231 million, net of commissions of $2 million, from the issuance of units pursuant to an equity distribution agreement, which were used for general partnership purposes. All remaining units authorized under this distribution agreement were issued during October 2014.

In September 2014, Sunoco Logistics filed a registration statement which will allow it to issue up to an additional $1.0 billion of common units directly to the public under its equity distribution agreement.

Additionally, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.5 billion Sunoco Logistics Credit Facility and for general partnership purposes.

Sales of Common Units by Sunoco LP

In October 2014, Sunoco LP issued 8.0 million common units in an underwritten public offering. Net proceeds of $359 million from the offering were used to repay amounts outstanding under the $1.25 billion Sunoco LP Credit Facility and for general partnership purposes.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 19, 2014	$	0.34625
March 31, 2014	May 5, 2014	May 19, 2014	0.35875
June 30, 2014	August 4, 2014	August 19, 2014	0.38000
September 30, 2014	November 3, 2014	November 19, 2014	0.41500

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.9200
March 31, 2014	May 5, 2014	May 15, 2014	0.9350
June 30, 2014	August 4, 2014	August 14, 2014	0.9550
September 30, 2014	November 3, 2014	November 14, 2014	0.9750

In connection with previous transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods, and ETP has agreed to make incremental distributions on the Class H Units in future periods. The net impact of these adjustments will result in a reduction of $88 million in the distributions to be paid from ETP to ETE for the nine months endedSeptember 30, 2014. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods:

	Total Year
2014 (remainder)	$	35
2015	86
2016	107
2017	85
2018	80
2019	70

The amounts reflected above include the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE by ETP over the first forty fiscal quarters commencing immediately after the consummation of the Susser Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interest and the incentive distribution rights between ETE and ETP.

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.4750
March 31, 2014	May 8, 2014	May 15, 2014	0.4800
June 30, 2014	August 7, 2014	August 14, 2014	0.4900
September 30, 2014	November 7, 2014	November 14, 2014	0.5025

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2013:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 10, 2014	February 14, 2014	$	0.3312
March 31, 2014	May 9, 2014	May 15, 2014	0.3475
June 30, 2014	August 8, 2014	August 14, 2014	0.3650
September 30, 2014	November 7, 2014	November 14, 2014	0.3825

Sunoco Logistics Unit Split

On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014:

Quarter Ended	Record Date	Payment Date	Rate
September 30, 2014	November 18, 2014	November 28, 2014	$	0.5457

Accumulated Other Comprehensive Income

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

	September 30, 2014			December 31, 2013
Available-for-sale securities	$	3		$	2
Foreign currency translation adjustment	(4		)	(1		)
Net loss on commodity related hedges	(1		)	(4		)
Actuarial gain related to pensions and other postretirement benefits	54			56
Investments in unconsolidated affiliates, net	2			8
Subtotal	54			61
Amounts attributable to noncontrolling interest	(49		)	(52		)
Total AOCI, net of tax	$	5		$	9

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Price Risk Management Assets And Liabilities Narrative (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
ETP [Member]
Expected gains (losses) related to derivatives to be reclassified into earnings over next year related to amounts currently reported an AOCI	$ 1
Regency [Member]
Notional Amount of Credit Risk Derivatives	10
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 2

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Price Risk Management Assets And Liabilities Table - Interest Rate Swaps Outstanding (Details) (Interest Rate Derivatives [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014		Dec. 31, 2013
Forward Starting July 2014 [Member] | ETP [Member]
Notional Amount	$ 0	[1]	$ 400	[1]
Type	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	[2]
July 2015 [Member] | ETP [Member]
Notional Amount	200	[1]	0	[1]
Type	Forward-starting to pay a fixed rate of 3.38% and receive a floating rate	[1],[2]
Forward Starting July 2016 [Member] | ETP [Member]
Notional Amount	200	[3]	0	[3]
Type	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	[2],[3]
July 2017 [Member] | ETP [Member]
Notional Amount	200	[4]	0	[4]
Type	Forward-starting to pay a fixed rate of 4.18% and receive a floating rate	[2],[4]
Forward Starting July 2018 [Member] | ETP [Member]
Notional Amount	200	[4]	0	[4]
Type	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	[2],[4]
July 2018 [Member] | ETP [Member]
Notional Amount	0		600
Type	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	[2]
July 2021 [Member] | ETP [Member]
Notional Amount	0		400
Type	Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%	[2]
February 2023 [Member] | ETP [Member]
Notional Amount	200		400
Type	Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%	[2]
November 2021 [Member] | Panhandle [Member]
Notional Amount	$ 125		$ 275
Type	Pay a fixed rate of 3.82% and receive a floating rate	[2]

[1] (2) Represents the effective date. These forward starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.

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

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

[4] (4) Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Rent expense table (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Operating Leases, Rent Expense, Contingent Rentals	$ 8		$ 8		$ 17		$ 18
Operating Leases, Rent Expense	31	[1]	33	[1]	90	[1]	98	[1]
Operating Leases, Rent Expense, Sublease Rentals	9		6		27		16
Operating Leases, Rent Expense, Net	$ 22		$ 27		$ 63		$ 82

[1] (1) Includes contingent rentals totaling $8 million for the three months ended September 30, 2014 and 2013, and $17 million and $18 million for the nine months ended September 30, 2014 and 2013, respectively.

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2014

BENEFITS [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

The following table sets forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans:

	Three Months Ended September 30,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—		$	—		$	—		$	(1	)
Interest cost	8			1			10			2
Expected return on plan assets	(10		)	(2		)	(15		)	(3		)
Prior service cost amortization	—			—			—			1
Actuarial loss amortization	—			—			1			—
Settlement credits	(1		)	—			—			—
	(3		)	(1		)	(4		)	(1		)
Regulatory adjustment	—			—			1			—
Net periodic benefit cost	$	(3	)	$	(1	)	$	(3	)	$	(1	)

	Nine Months Ended September 30,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	1		$	—		$	5		$	—
Interest cost	23			4			28			5
Expected return on plan assets	(30		)	(6		)	(45		)	(7		)
Prior service cost amortization	—			—			—			1
Actuarial (gain) loss amortization	(1		)	—			2			—
Settlement credits	(3		)	—			(2		)	—
	(10		)	(2		)	(12		)	(1		)
Regulatory adjustment	—			—			5			—
Net periodic benefit cost	$	(10	)	$	(2	)	$	(7	)	$	(1	)

Panhandle has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and reflected in expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

Panhandle no longer has pension plans after the sale of the assets of Missouri Gas Energy and New England Gas Company in 2013.

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Net Income per Limited Partner Unit Table - Income Reconciliation (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Income from continuing operations	$ 470	$ 343	$ 1,352	$ 972
Less: Income from continuing operations attributable to noncontrolling interest	282	195	839	623
Income from continuing operations, net of noncontrolling interest	188	148	513	349
Less: General Partner’s interest in income from continuing operations	0	1	1	1
Less: Class D Unitholder’s interest in income from continuing operations	0	0	1	0
Income from continuing operations available to Limited Partners	188	147	511	348
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average Limited Partner units	538.8	561.4	546.6	560.8
Basic income from continuing operations per Limited Partner unit	$ 0.35	$ 0.26	$ 0.94	$ 0.62
Basic income from discontinued operations per Limited Partner unit	$ 0.00	$ 0.01	$ 0.01	$ 0.03
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1)	0	(2)	(1)
Diluted income from continuing operations available to Limited Partners	$ 187	$ 147	$ 509	$ 347
Dilutive effect of unconverted unit awards	1.1	0	1.0	0
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	539.9	561.4	547.6	560.8
Diluted income from continuing operations per Limited Partner unit	$ 0.35	$ 0.26	$ 0.93	$ 0.62
Diluted income from discontinued operations per Limited Partner unit	$ 0.00	$ 0.01	$ 0.01	$ 0.03

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Related Party Transactions

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various 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 $261 million and $951 million during the three and nine months ended September 30, 2014, respectively, and $387 million and $1.08 billion during the three and nine months ended September 30, 2013, respectively.

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Acquisitions Acquisition Tables (Tables)

9 Months Ended

Sep. 30, 2014

Business Acquisition [Line Items]

Business Acquisition, Pro Forma Information [Table Text Block]

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2014 and 2013 are presented as if the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assume there were no other changes in operations. This pro forma information does not necessarily reflect the actual results that would have occurred had the acquisitions occurred on January 1, 2013, nor is it indicative of future results of operations. Actual results for the three months ended September 30, 2014 include PVR and the Eagle Rock midstream business for the entire period.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenues	$	14,987	$	13,042	$	43,036	$	37,310
Net income attributable to partners	188		138		496		324
Basic net income per Limited Partner unit	$	0.35	$	0.25	$	0.91	$	0.58
Diluted net income per Limited Partner unit	$	0.35	$	0.25	$	0.91	$	0.58

Susser Merger [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:

	Susser
Total current assets	$	422
Property, plant and equipment	1,065
Goodwill(1)	1,605
Intangible assets	481
Other non-current assets	27
	3,600
Current liabilities	377
Long-term debt, less current maturities	564
Deferred income taxes	432
Other non-current liabilities	40
Noncontrolling interest	404
	1,817
Total consideration	1,783
Cash received	67
Total consideration, net of cash received	$	1,716

⁽¹⁾  None of the goodwill is expected to be deductible for tax purposes.

Eagle Rock Midstream Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

Regency’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:

Assets	At July 1, 2014
Current assets	$	115
Property, plant and equipment	1,329
Other long-term assets	4
Total assets acquired	1,448
Liabilities
Current liabilities	109
Long-term debt	499
Long-term liabilities	12
Total liabilities assumed	620
Net assets acquired	$	828

PVR Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At March 21, 2014
Current assets	$	149
Property, plant and equipment	2,716
Investment in unconsolidated affiliates	62
Intangible assets (average useful lives of 30 years)	2,717
Goodwill	370
Other long-term assets	18
Total assets acquired	6,032
Liabilities
Current liabilities	168
Long-term debt	1,788
Premium related to senior notes	99
Long-term liabilities	30
Total liabilities assumed	2,085
Net assets acquired	$	3,947

Hoover Midstream Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:

Assets	At February 3, 2014
Current assets	$	5
Property, plant and equipment	117
Intangible assets (average useful lives of 30 years)	148
Goodwill	30
Total assets acquired	300
Liabilities
Current liabilities	5
Asset retirement obligations	2
Total liabilities assumed	7
Net assets acquired	$	293

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Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Liabilities, Fair Value Disclosure, Recurring	$ 234	$ (347)
Fair Value, Inputs, Level 1 [Member]
Liabilities, Fair Value Disclosure, Recurring	107	(215)
Fair Value, Inputs, Level 2 [Member]
Liabilities, Fair Value Disclosure, Recurring	97	(113)
Level 3 [Member]
Liabilities, Fair Value Disclosure, Recurring	30	(19)
Commodity Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	1
Commodity Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0
Commodity Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	1
Commodity Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0
Fair Value, Measurements, Recurring [Member]
Interest Rate Derivative Assets, at Fair Value	3	47
Price Risk Derivative Assets, at Fair Value	130	231
Assets, Fair Value Disclosure	133	278
Interest Rate Derivative Liabilities, at Fair Value	(86)	(95)
Embedded Derivative, Fair Value of Embedded Derivative Liability	(30)	(19)
Price Risk Derivative Liabilities, at Fair Value	(118)	(233)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Interest Rate Derivative Assets, at Fair Value	0	0
Price Risk Derivative Assets, at Fair Value	109	217
Assets, Fair Value Disclosure	109	217
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	(107)	(215)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Interest Rate Derivative Assets, at Fair Value	3	47
Price Risk Derivative Assets, at Fair Value	21	14
Assets, Fair Value Disclosure	24	61
Interest Rate Derivative Liabilities, at Fair Value	(86)	(95)
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	0
Price Risk Derivative Liabilities, at Fair Value	(11)	(18)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Interest Rate Derivative Assets, at Fair Value	0	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	(30)	(19)
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	4
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	4
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 3 [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	0
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	6	5
Price Risk Derivative Liabilities, at Fair Value	(8)	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	6	8
Price Risk Derivative Liabilities, at Fair Value	(5)	(6)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	75	203
Price Risk Derivative Liabilities, at Fair Value	(75)	(206)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	6	5
Price Risk Derivative Liabilities, at Fair Value	(8)	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	1	1
Price Risk Derivative Liabilities, at Fair Value	(1)	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	69	201
Price Risk Derivative Liabilities, at Fair Value	(73)	(201)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | 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] | Fair Value, Inputs, Level 2 [Member] | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	5	7
Price Risk Derivative Liabilities, at Fair Value	(4)	(6)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	6	2
Price Risk Derivative Liabilities, at Fair Value	(2)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | 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 [Member] | 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 [Member] | 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 [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Forward Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value		(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	19	5
Price Risk Derivative Liabilities, at Fair Value	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value		(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Inputs, Level 1 [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	19	5
Price Risk Derivative Liabilities, at Fair Value	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Fair Value, Inputs, Level 2 [Member] | Future [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] | Level 3 [Member] | Forward Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Future [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 - Power [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	2	3
Price Risk Derivative Liabilities, at Fair Value	(2)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	1
Price Risk Derivative Liabilities, at Fair Value	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 1 [Member] | 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] | Fair Value, Inputs, Level 1 [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	1
Price Risk Derivative Liabilities, at Fair Value	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	2	3
Price Risk Derivative Liabilities, at Fair Value	(2)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | 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 [Member] | 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 [Member] | 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 - NGLs [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	16	7
Price Risk Derivative Liabilities, at Fair Value	(19)	(9)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	13	5
Price Risk Derivative Liabilities, at Fair Value	(18)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	3	2
Price Risk Derivative Liabilities, at Fair Value	(1)	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 [Member] | 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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Acquisitions Narrative (Details) (USD $)	3 Months Ended		9 Months Ended					1 Months Ended	0 Months Ended	3 Months Ended		1 Months Ended		1 Months Ended	9 Months Ended				9 Months Ended			1 Months Ended				1 Months Ended	3 Months Ended	9 Months Ended					3 Months Ended	9 Months Ended		9 Months Ended							0 Months Ended	1 Months Ended				1 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jan. 09, 2014	Oct. 01, 2014 MACS Transaction [Member] Company owned retail stores [Member] sites	Oct. 01, 2014 MACS Transaction [Member] Dealer operated and consignment [Member] sites	Sep. 30, 2014 Aloha Acquisition [Member]	Aug. 01, 2014 Susser Merger [Member]	Sep. 30, 2014 Susser Merger [Member]	Aug. 29, 2014 Susser Merger [Member]	Jul. 31, 2014 Eagle Rock Midstream Acquisition [Member]	Mar. 03, 2014 Hoover Midstream Acquisition [Member]	Oct. 31, 2014 MACS Transaction [Member]	Sep. 30, 2014 Susser [Member]	Sep. 30, 2014 Sunoco LP [Member]	Oct. 01, 2014 Sunoco LP [Member]	Oct. 01, 2014 Sunoco LP [Member] MACS Transaction [Member]	Sep. 30, 2014 Eagle Rock [Member]	Sep. 30, 2014 Regency [Member]	Dec. 31, 2013 Regency [Member]	Jul. 31, 2014 Regency [Member] ETE Common Holdings [Member]	Jun. 30, 2014 Regency [Member] ETE Common Holdings [Member]	Mar. 21, 2014 Regency [Member] PVR Acquisition [Member]	Sep. 30, 2014 Regency [Member] Eagle Rock Midstream Acquisition [Member]	Feb. 28, 2014 Regency [Member] Hoover Midstream Acquisition [Member]	Sep. 30, 2014 PVR [Member]	Sep. 30, 2014 PVR [Member]	Mar. 21, 2014 PVR [Member]	Dec. 31, 2013 PVR [Member]	Sep. 30, 2014 ETP [Member]	Dec. 31, 2013 ETP [Member]	Sep. 30, 2014 Hoover Midstream Acquisition [Member]	Sep. 30, 2014 Hoover Midstream Acquisition [Member]	Jan. 09, 2014 Panhandle [Member] ETP [Member]	Sep. 30, 2014 ETP [Member] Susser [Member]	Sep. 30, 2014 ETP [Member] Sunoco LP [Member]	Jan. 09, 2014 7.60% Senior Notes, due February 1, 2024 [Member]	Jan. 09, 2014 8.25% Senior Notes, due November 14, 2029 [Member]	Jul. 01, 2014 8.375% Senior Notes due June 1, 2019 [Member] Eagle Rock [Member]	Sep. 30, 2014 8.375% Senior Notes due June 1, 2019 [Member] PVR [Member]	Jan. 09, 2014 Class F Units [Member] Panhandle [Member] Regency [Member] SUGS Contribution [Member]	Aug. 01, 2014 Common Units [Member] Sunoco LP [Member] Susser Merger [Member]	Mar. 21, 2014 Common Units [Member] Regency [Member] PVR Acquisition [Member]	Mar. 21, 2014 Common Units [Member] Regency [Member] Eagle Rock Midstream Acquisition [Member]	Feb. 28, 2014 Common Units [Member] Regency [Member] Hoover Midstream Acquisition [Member]	Jan. 09, 2014 Common Units [Member] Panhandle [Member] Regency [Member] SUGS Contribution [Member]	Feb. 28, 2014 Lake Charles LNG Transaction [Member]	Feb. 28, 2014 Trunkline LNG Transaction [Member]
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax			$ 39,000,000
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount																				272,000,000
Senior Notes																				4,899,000,000	2,800,000,000						789,000,000	789,000,000	1,200,000,000	0	10,890,000,000	11,182,000,000								499,000,000	473,000,000
Proceeds from Issuance of Common Stock																359,000,000						400,000,000	400,000,000
Limited Partners' Capital Account, Units Issued																	8,000,000	4,000,000							8,200,000
Debt Instrument, Interest Rate, Stated Percentage																																						7.60%	8.25%		8.375%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares									15,800,000																																		11,000,000	140,400,000	8,200,000	4,040,471
Number of Stores						110	200				630
Payments for Merger Related Costs										24,000,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest																																				100.00%	44.00%
Business Combination, Consideration Transferred								240,000,000	1,800,000,000			1,300,000,000		768,000,000										5,700,000,000		293,000,000
Business Acquisition, Share Price																								$ 27.82
Noncash or Part Noncash Divestiture, Amount of Consideration Received																								1,800,000,000
Business Acquisition, Cost of Acquired Entity, Cash Paid									875,000,000					556,000,000										36,000,000		184,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other													2,000,000
Revenues	14,987,000,000	12,486,000,000	42,210,000,000	35,728,000,000											575,000,000				472,000,000								302,000,000	653,000,000					11,000,000	26,000,000
Net Income (Loss) Attributable to Parent	188,000,000	151,000,000	520,000,000	368,000,000
Number Of Share Received In Exchange Of Each Share																								1.02
Number of common units of a subsidiary partnership that are held by a less than wholly-owned subsidiary of the Parent.																																										6,300,000					31,400,000
Number of common units of a subsidiary partnership that are held by a wholly-owned subsidiary of the Parent.																																			2,200,000
Guarantor Obligations, Current Carrying Value					600,000,000
Partners' Capital Account, Units, Redeemed																																																	18,700,000
Related Party Transaction, Amounts of Transaction																																																75,000,000
Net income	$ 470,000,000	$ 356,000,000	$ 1,418,000,000	$ 1,016,000,000											$ 2,000,000				$ 18,000,000								$ 84,000,000	$ 119,000,000					$ (2,000,000)	$ 2,000,000

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Consolidated Statement Of Equity (USD $) In Millions	Total	General Partner	Common Unitholders	Class D Units	Accumulated Other Comprehensive Income	Non- controlling Interest	Subsidiary units issued for cash [Member]	Subsidiary units issued for cash [Member] General Partner	Subsidiary units issued for cash [Member] Common Unitholders	Subsidiary units issued for cash [Member] Class D Units	Subsidiary units issued for cash [Member] Accumulated Other Comprehensive Income	Subsidiary units issued for cash [Member] Non- controlling Interest	Subsidiary units issued in certain acquisitions [Member]	Subsidiary units issued in certain acquisitions [Member] General Partner	Subsidiary units issued in certain acquisitions [Member] Common Unitholders	Subsidiary units issued in certain acquisitions [Member] Class D Units	Subsidiary units issued in certain acquisitions [Member] Accumulated Other Comprehensive Income	Subsidiary units issued in certain acquisitions [Member] Non- controlling Interest	Subsidiary units issued to Parent [Member]	Subsidiary units issued to Parent [Member] General Partner	Subsidiary units issued to Parent [Member] Common Unitholders	Subsidiary units issued to Parent [Member] Class D Units	Subsidiary units issued to Parent [Member] Accumulated Other Comprehensive Income	Subsidiary units issued to Parent [Member] Non- controlling Interest
Balance, December 31, 2013 at Dec. 31, 2013	$ 16,279	$ (3)	$ 1,066	$ 6	$ 9	$ 15,201
Distributions to partners	(596)	(1)	(593)	(2)	0	0
Distributions to noncontrolling interest	(1,359)	0	0	0	0	(1,359)
Increase from subsidiary equity issuances							1,881	0	106	2	0	1,773	5,593	0	211	0	0	5,382	0	0	(99)	0	0	99
Subsidiary units redeemed in Lake Charles LNG Transaction	0	2	480	0	0	(482)
Non-cash compensation expense, net of units tendered by employees for tax withholdings	58	0	0	11	0	47
Capital contributions received from noncontrolling interest	19	0	0	0	0	19
Other, net	7	0	(2)	0	0	9
Units repurchased under buyback program	(1,000)	0	(1,000)	0	0	0
Other comprehensive loss, net of tax	(7)	0	0	0	(4)	(3)
Net income	1,418	1	518	1	0	898
Balance, September 30, 2014 at Sep. 30, 2014	$ 22,293	$ (1)	$ 687	$ 18	$ 5	$ 21,584

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Cash And Cash Equivalents

9 Months Ended

Sep. 30, 2014

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.

Non-cash investing and financing activities were as follows:

	Nine Months Ended September 30,
	2014		2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	399	$	260
Net gains (losses) from subsidiary common unit transactions	$	702	$	(410	)
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions	$	4,281	$	—
Subsidiary issuances of common units in connection with Susser Merger	$	1,312	$	—
Long-term debt assumed in PVR Acquisition	$	1,887	$	—
Long-term debt exchanged in Eagle Rock Midstream Acquisition	$	499	$	—

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Equity Table - Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 3	$ 2
Foreign currency translation adjustment	(4)	(1)
Net loss on commodity related hedges	(1)	(4)
Actuarial gain related to pensions and other postretirement benefits	54	56
Investments in unconsolidated affiliates, net	2	8
Subtotal	54	61
Amounts attributable to noncontrolling interest	(49)	(52)
Accumulated other comprehensive income, net	$ 5	$ 9

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Price Risk Management Assets And Liabilities Table - Partnership's Derivative Assets and Liabilities Recognized OCI on Derivatives (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 3	$ (4)	$ (3)	$ 4
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 3	$ (4)	$ (3)	$ 4

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Advances to and Investments in Unconsolidated Affiliates (Tables)

9 Months Ended

Sep. 30, 2014

INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract]

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

The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenue	$	919	$	883	$	3,703	$	3,324
Operating income	206		196		881		839
Net income	82		64		505		460

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Reportable Segments Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Segment Reporting Information [Line Items]
Revenues	$ 14,987	$ 12,486	$ 42,210	$ 35,728
Regency [Member] | Lone Star L.L.C. [Member]
Segment Reporting Information [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			30.00%
External Customers [Member] | Investment in Lake Charles LNG [Member]
Segment Reporting Information [Line Items]
Revenues	$ 55	$ 55	$ 162	$ 162

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Reportable Segments (Tables)

9 Months Ended

Sep. 30, 2014

Operating Segments [Member]

Financial Information By Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Segment Adjusted EBITDA:
Investment in ETP	$	1,172		$	942		$	3,547		$	2,967
Investment in Regency	344			172			856			446
Investment in Lake Charles LNG	51			47			146			139
Corporate and Other	(18		)	(9		)	(73		)	(38		)
Adjustments and Eliminations	(78		)	(103		)	(190		)	(250		)
Total	1,471			1,049			4,286			3,264
Depreciation, depletion and amortization	(425		)	(332		)	(1,248		)	(962		)
Interest expense, net of interest capitalized	(356		)	(298		)	(1,015		)	(913		)
Gain on sale of AmeriGas common units	14			87			177			87
Gains (losses) on interest rate derivatives	(25		)	3			(73		)	55
Non-cash unit-based compensation expense	(20		)	(16		)	(60		)	(43		)
Unrealized gains (losses) on commodity risk management activities	32			22			(11		)	45
Gains (losses) on extinguishment of debt	2			—			2			(7		)
LIFO valuation adjustments	(51		)	6			(17		)	22
Equity in earnings of unconsolidated affiliates	84			38			265			182
Adjusted EBITDA related to unconsolidated affiliates	(183		)	(165		)	(583		)	(553		)
Adjusted EBITDA related to discontinued operations	—			(12		)	(27		)	(75		)
Other, net	(17		)	10			(73		)	6
Income from continuing operations before income tax expense	$	526		$	392		$	1,623		$	1,108

Assets Segments [Member]

Financial Information By Segment

	September 30, 2014			December 31, 2013
Total assets:
Investment in ETP	$	48,571		$	43,702
Investment in Regency	17,180			8,782
Investment in Lake Charles LNG	1,170			1,338
Corporate and Other	804			720
Adjustments and Eliminations	(3,044		)	(4,212		)
Total	$	64,681		$	50,330

Sales Revenue, Segment [Member]

Financial Information By Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues:
Investment in ETP:
Revenues from external customers	$	13,573		$	11,848		$	38,778		$	34,214
Intersegment revenues	45			54			101			93
	13,618			11,902			38,879			34,307
Investment in Regency:
Revenues from external customers	1,381			633			3,282			1,796
Intersegment revenues	102			32			242			48
	1,483			665			3,524			1,844
Investment in Lake Charles LNG:
Revenues from external customers	55			55			162			162
Adjustments and Eliminations	(169		)	(136		)	(355		)	(585		)
Total revenues	$	14,987		$	12,486		$	42,210		$	35,728

Investment In ETP [Member]

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

Investment in ETP

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Intrastate Transportation and Storage	$	559	$	502	$	2,075	$	1,705
Interstate Transportation and Storage	254		296		794		973
Midstream	311		334		915		973
Liquids Transportation and Services	1,165		537		2,844		1,303
Investment in Sunoco Logistics	4,862		4,502		14,080		12,215
Retail Marketing	5,985		5,297		16,561		15,805
All Other	482		434		1,610		1,333
Total revenues	13,618		11,902		38,879		34,307
Less: Intersegment revenues	45		54		101		93
Revenues from external customers	$	13,573	$	11,848	$	38,778	$	34,214

Investment In Regency [Member]

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

Investment in Regency

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Gathering and Processing	$	1,387	$	603	$	3,254	$	1,671
Contract Services	76		58		217		159
Natural Resources	18		—		40		—
Corporate and Other	2		4		13		14
Total revenues	1,483		665		3,524		1,844
Less: Intersegment revenues	102		32		242		48
Revenues from external customers	$	1,381	$	633	$	3,282	$	1,796

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Price Risk Management Assets And Liabilities

9 Months Ended

Sep. 30, 2014

General Discussion of Derivative Instruments and Hedging Activities [Abstract]

Price Risk Management Assets And Liabilities

PRICE RISK MANAGEMENT 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. Following is a description of price risk management activities by operating entity.

ETP

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges 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. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of ETP’s derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s interstate transportation and storage segment. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in ETP’s midstream segment whereby ETP’s 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 NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP may use derivatives in ETP’s NGL transportation and services segment to manage ETP’s storage facilities and the purchase and sale of purity NGLs.

Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.

ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used 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. The derivatives used in ETP’s retail marketing operations represent economic hedges; however, ETP has elected not to designate any of the hedges in these operations. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.

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

The following table details ETP’s outstanding commodity-related derivatives:

	September 30, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	920,000		2014-2015	9,457,500		2014-2019
Basis Swaps IFERC/NYMEX (1)	2,882,500		2014-2015	(487,500	)	2014-2017
Options – Puts	5,000,000		2015	—		—
Swing Swaps	—		—	1,937,500		2014-2016
Power (Megawatt):
Forwards	343,775		2014	351,050		2014
Futures	(57,744	)	2014	(772,476	)	2014
Options — Puts	(54,400	)	2014	(52,800	)	2014
Options — Calls	54,400		2014	103,200		2014
Crude (Bbls) — Futures	(81,000	)	2014	103,000		2014
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(7,182,500	)	2014-2015	570,000		2014
Swing Swaps IFERC	17,790,000		2014	(9,690,000	)	2014-2016
Fixed Swaps/Futures	(8,067,500	)	2014-2019	(8,195,000	)	2014-2015
Forward Physical Contracts	(9,325,164	)	2014-2015	5,668,559		2014-2015
Natural Gas Liquid (Bbls) — Forwards/Swaps	(1,602,800	)	2014-2015	(1,133,600	)	2014
Refined Products (Bbls) — Futures	(243,000	)	2014-2015	(280,000	)	2014
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(24,197,500	)	2015	(7,352,500	)	2014
Fixed Swaps/Futures	(24,197,500	)	2015	(50,530,000	)	2014
Hedged Item — Inventory	24,197,500		2015	50,530,000		2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(460,000	)	2014	(1,825,000	)	2014
Fixed Swaps/Futures	(3,220,000	)	2014	(12,775,000	)	2014
Natural Gas Liquid (Bbls) — Forwards/Swaps	(255,000	)	2014	(780,000	)	2014
Crude (Bbls) — Futures	—		—	(30,000	)	2014

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

We expect gains of less than $1 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Regency

Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.

Commodity Derivative Instruments - Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency’s activities are governed by its risk policy. As part of its natural gas marketing and trading activities, Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales. Through Regency’s natural gas marketing activity, Regency will have credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty.

The following table details Regency’s outstanding commodity-related derivatives:

	September 30, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(13,289,000	)	2014-2015	(24,455,000	)	2014-2015
Propane (Gallons) — Forwards/Swaps	(44,562,000	)	2014-2015	(52,122,000	)	2014-2015
NGLs (Barrels) — Forwards/Swaps	(439,000	)	2014-2015	(438,000	)	2014
WTI Crude Oil (Barrels) — Forwards/Swaps	(1,715,000	)	2014-2016	(521,000	)	2014

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
Entity	Term	Type(1)	September 30, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	—	$	400
ETP	July 2015(2)	Forward-starting to pay a fixed rate of 3.38% and receive a floating rate	200		—
ETP	July 2016(3)	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	200		—
ETP	July 2017(4)	Forward-starting to pay a fixed rate of 4.18% and receive a floating rate	200		—
ETP	July 2018(4)	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		—
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	—		600
ETP	June 2021	Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%	—		400
ETP	February 2023	Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%	200		400
Panhandle	November 2021	Pay a fixed rate of 3.82% and receive a floating rate	125		275

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

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

⁽³⁾  Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.

⁽⁴⁾  Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

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

ETP’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, utilities and midstream companies. ETP’s overall exposure may be affected positively or negatively by macroeconomic 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.

Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of September 30, 2014 would be $10 million, which would be reduced by $2 million, due to the netting features. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations.

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

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014			December 31, 2013
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	2	$	3	$	(3	)	$	(18	)
	2		3		(3		)	(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	114	$	227	$	(110	)	$	(209	)
Commodity derivatives	25		43		(16		)	(48		)
Interest rate derivatives	3		47		(86		)	(95		)
Embedded derivatives in Regency Preferred Units	—		—		(30		)	(19		)
	142		317		(242		)	(371		)
Total derivatives	$	144	$	320	$	(245	)	$	(389	)

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

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2014			December 31, 2013			September 30, 2014			December 31, 2013
Derivatives in offsetting agreements:
OTC contracts	Price risk management asset (liability)	$	12		$	42		$	(12	)	$	(38	)
Broker cleared derivative contracts	Other current assets	130			264			(152		)	(318		)
		142			306			(164		)	(356		)
Offsetting agreements:
Counterparty netting	Price risk management asset (liability)	(9		)	(36		)	9			36
Payments on margin deposit	Other current assets	(5		)	(1		)	30			55
		(14		)	(37		)	39			91
Net derivatives with offsetting agreements		128			269			(125		)	(265		)
Derivatives without offsetting agreements		16			51			(120		)	(124		)
Total derivatives		$	144		$	320		$	(245	)	$	(389	)

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 September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	3	$	(4	)	$	(3	)	$	4
Total	$	3	$	(4	)	$	(3	)	$	4

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	—	$	3	$	(6	)	$	5
Total		$	—	$	3	$	(6	)	$	5

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014			2013
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	1	$	—	$	(5	)	$	4
Total		$	1	$	—	$	(5	)	$	4

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2014			2013			2014			2013
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(4	)	$	(11	)	$	(2	)	$	(12	)
Commodity derivatives – Non-trading	Cost of products sold	52			(34		)	9			(20		)
Commodity derivatives – Non-trading	Deferred gas purchases	—			—			—			(3		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(25		)	3			(73		)	55
Embedded derivatives	Other income	(1		)	24			(11		)	2
Total		$	22		$	(18	)	$	(77	)	$	22