10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 May 2, 2014, the registrant had 543,712,024 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 (Loss)	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	41
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	56
ITEM 4. CONTROLS AND PROCEDURES	59
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	60
ITEM 1A. RISK FACTORS	60
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60
ITEM 6. EXHIBITS	61
SIGNATURE	62

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
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
EPA	U.S. Environmental Protection Agency
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
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas

ii

Lone Star	Lone Star NGL LLC
MACS	Mid-Atlantic Convenience Stores, LLC
MGE	Missouri Gas Energy
MEP	Midcontinent Express Pipeline LLC
MMBtu	million British thermal units
MTBE	methyl tertiary butyl ether
NEG	New England Gas Company
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 Holdings	Susser Holdings Corporation
Susser Petroleum	Susser Petroleum Partners, LP
Transwestern	Transwestern Pipeline Company, LLC
Trunkline LNG	Trunkline LNG 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, 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)

	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,010		$	590
Accounts receivable, net	4,423			3,658
Accounts receivable from related companies	40			63
Inventories	1,484			1,807
Exchanges receivable	101			67
Price risk management assets	12			39
Current assets held for sale	167			—
Other current assets	279			312
Total current assets	7,516			6,536
PROPERTY, PLANT AND EQUIPMENT	37,679			33,917
ACCUMULATED DEPRECIATION	(3,564		)	(3,235		)
	34,115			30,682
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,818			4,014
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	1			18
GOODWILL	6,216			5,894
INTANGIBLE ASSETS, net	5,132			2,264
OTHER NON-CURRENT ASSETS, net	971			922
Total assets	$	57,769		$	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)

	March 31, 2014			December 31, 2013
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	4,272		$	3,834
Accounts payable to related companies	10			14
Exchanges payable	284			284
Price risk management liabilities	70			53
Accrued and other current liabilities	1,958			1,678
Current maturities of long-term debt	1,388			637
Current liabilities held for sale	109			—
Total current liabilities	8,091			6,500
LONG-TERM DEBT, less current maturities	24,905			22,562
DEFERRED INCOME TAXES	3,700			3,865
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	59			73
OTHER NON-CURRENT LIABILITIES	1,024			1,019
COMMITMENTS AND CONTINGENCIES (Note 12)
PREFERRED UNITS OF SUBSIDIARY	32			32
EQUITY:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	1,271			1,066
Class D Units	10			6
Accumulated other comprehensive income	6			9
Total partners’ capital	1,286			1,078
Noncontrolling interest	18,672			15,201
Total equity	19,958			16,279
Total liabilities and equity	$	57,769		$	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 March 31,
	2014			2013
REVENUES:
Natural gas sales	$	1,430		$	973
NGL sales	1,254			713
Crude sales	4,093			3,201
Gathering, transportation and other fees	872			740
Refined product sales	4,478			4,662
Other	953			890
Total revenues	13,080			11,179
COSTS AND EXPENSES:
Cost of products sold	11,442			9,807
Operating expenses	407			372
Depreciation and amortization	373			312
Selling, general and administrative	148			157
Total costs and expenses	12,370			10,648
OPERATING INCOME	710			531
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(315		)	(310		)
Equity in earnings of unconsolidated affiliates	104			90
Gains (losses) on interest rate derivatives	(2		)	6
Gain on sale of AmeriGas common units	70			—
Other, net	2			(19		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	569			298
Income tax expense (benefit) from continuing operations	145			(2		)
INCOME FROM CONTINUING OPERATIONS	424			300
Income from discontinued operations	24			22
NET INCOME	448			322
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	280			232
NET INCOME ATTRIBUTABLE TO PARTNERS	168			90
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	167		$	90
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.30		$	0.14
Diluted	$	0.30		$	0.14
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.30		$	0.16
Diluted	$	0.30		$	0.16

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

3

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in millions)

(unaudited)

	Three Months Ended March 31,
	2014			2013
Net income	$	448		$	322
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	4			(1		)
Change in value of derivative instruments accounted for as cash flow hedges	(4		)	2
Change in value of available-for-sale securities	—			1
Actuarial loss relating to pension and other postretirement benefits	(1		)	(1		)
Foreign currency translation adjustment	(3		)	(1		)
Change in other comprehensive income from equity investments	(7		)	7
	(11		)	7
Comprehensive income	437			329
Less: Comprehensive income attributable to noncontrolling interest	272			238
Comprehensive income attributable to partners	$	165		$	91

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 THREE MONTHS ENDED MARCH 31, 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	—			(194		)	(1		)	—			—			(195		)
Distributions to noncontrolling interest	—			—			—			—			(397		)	(397		)
Subsidiary units issued for cash	—			17			—			—			158			175
Subsidiary units issued in certain acquisitions	—			104			—			—			3,911			4,015
Subsidiary units redeemed in Trunkline LNG Transaction	2			480			—			—			(482		)	—
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			4			—			13			17
Other, net	—			(3		)	—			—			(4		)	(7		)
Units repurchased under buyback program	—			(366		)	—			—			—			(366		)
Other comprehensive loss, net of tax	—			—			—			(3		)	(8		)	(11		)
Net income	—			167			1			—			280			448
Balance, March 31, 2014	$	(1	)	$	1,271		$	10		$	6		$	18,672		$	19,958

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)

	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	448		$	322
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	373			312
Deferred income taxes	(109		)	3
Amortization included in interest expense	(12		)	(16		)
Non-cash compensation expense	20			16
Gain on sale of AmeriGas common units	(70		)	—
LIFO valuation adjustments	(14		)	(38		)
Equity in earnings of unconsolidated affiliates	(104		)	(90		)
Distributions from unconsolidated affiliates	67			100
Other non-cash	(16		)	17
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation	246			(296		)
Net cash provided by operating activities	829			330
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(214		)	—
Cash proceeds from the sale of AmeriGas common units	381			—
Capital expenditures (excluding allowance for equity funds used during construction)	(942		)	(761		)
Contributions in aid of construction costs	7			8
Contributions to unconsolidated affiliates	(50		)	(1		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	27			30
Proceeds from the sale of assets	11			21
Other	(21		)	3
Net cash used in investing activities	(801		)	(700		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	3,170			2,899
Repayments of long-term debt	(1,977		)	(1,961		)
Subsidiary equity offerings, net of issue costs	175			192
Distributions to partners	(195		)	(179		)
Debt issuance costs	(17		)	(16		)
Distributions to noncontrolling interest	(397		)	(333		)
Capital contributions received from noncontrolling interest	—			11
Units repurchased under buyback program	(366		)	—
Other, net	(1		)	(1		)
Net cash provided by financing activities	392			612
INCREASE IN CASH AND CASH EQUIVALENTS	420			242
CASH AND CASH EQUIVALENTS, beginning of period	590			372
CASH AND CASH EQUIVALENTS, end of period	$	1,010		$	614

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.

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, Trunkline LNG, which 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 Trunkline 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 17 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 our 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 our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star and also owns MACS, a convenience store operator.

• 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.

7

• Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco. As discussed in Note 2, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. 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.

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

• Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. 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 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.

• Trunkline 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. Trunkline LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

Our reportable segments 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 Trunkline LNG, including the operations of Trunkline 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 March 31, 2014 and for the three months ended March 31, 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 March 31, 2014, and the Partnership’s results of operations and cash flows for the three months ended March 31, 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.

8

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 $530 million and $514 million for the three months ended March 31, 2014 and 2013, respectively.

New Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (“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:

Pending Transactions

ETP’s Pending Acquisition of Susser Holdings

On April 27, 2014, ETP entered into a definitive merger agreement whereby ETP plans to acquire Susser Holdings in a unit and cash transaction for total consideration valued at approximately $1.8 billion (the “Susser Merger”). By acquiring Susser Holdings, ETP will own the general partner interest and the incentive distribution rights in Susser Petroleum, approximately 11 million Susser Petroleum common units (representing approximately 50.2% of Susser Petroleum’s outstanding units), and Susser Holdings’ existing retail operations, consisting of 630 convenience store locations. The Susser Merger is expected to close in the third quarter of 2014, subject to approval of the shareholders of Susser Holdings and customary regulatory approvals.

Regency’s Pending Acquisition of Eagle Rock’s Midstream Business

In December 2013, Regency entered into an agreement to purchase Eagle Rock’s midstream business for approximately $1.3 billion (the “Eagle Rock Acquisition”). This acquisition is expected to complement Regency’s core gathering and processing business and, when combined with the PVR Acquisition, is expected to further diversify Regency’s basin exposure in the Texas Panhandle, East Texas and South Texas. On April 29, 2014, Eagle Rock’s unitholders approved the Eagle Rock Acquisition. After receiving that approval, all significant closing conditions have been met with the exception of the Federal Trade Commission’s (“FTC”) antitrust approval. On April 30, 2014, Regency and Eagle Rock certified substantial compliance with the FTC in response to its Request for Additional Information and Documentary Material regarding the Eagle Rock Acquisition.  In order to facilitate the FTC’s review, Eagle Rock and Regency have agreed with the FTC to not close the proposed transaction before June 30, 2014, unless the FTC first closes its investigation.

Closed Transactions

Panhandle Merger

On January 10, 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, a wholly-owned subsidiary of Southern Union, were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle as the surviving entity. 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.

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Trunkline LNG Transaction

On February 19, 2014, ETP completed the transfer to ETE of Trunkline 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 “Trunkline LNG Transaction”). This transaction waseffective as of January 1, 2014, at which time ETP deconsolidated Trunkline LNG, including goodwill of$184 millionand intangible assets of$50 millionrelated to Trunkline LNG.

In connection with ETE’s acquisition of Trunkline LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline 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 9.

Regency’s Acquisition of PVR

On March 21, 2014, Regency acquired all of the PVR outstanding units 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 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. From March 21, 2014 through March 31, 2014, revenues and net income attributable to PVR’s operations of $37 million and $2 million, respectively, are included in Regency’s results of operations.

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

	March 21, 2014
Current assets	$	150
Plant, property and equipment	2,687
Investment in unconsolidated affiliates	62
Goodwill and intangible assets	3,079
Total assets acquired	$	5,978
Current liabilities	166
Long-term debt	1,887
Asset retirement obligations	3
Net assets acquired	$	3,922

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. From February 3, 2014 through March 31, 2014, revenues and net income attributable to Hoover’s operations of $5 million and $2 million, respectively, included in Regency’s results of operations.

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

	February 3, 2014
Current assets	$	5
Property, plant and equipment	114
Goodwill and intangible assets	181
Total assets acquired	$	300
Current liabilities	5
Asset retirement obligations	2
Net assets acquired	$	293

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three months ended March 31, 2014 and 2013 are presented as if the PVR and Hoover 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.

	Three Months Ended March 31,
	2014		2013
Revenues	$	13,362	$	11,449
Net income attributable to partners	161		84
Basic net income per Limited Partner unit	$	0.29	$	0.15
Diluted net income per Limited Partner unit	$	0.29	$	0.15

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 three months ended March 31, 2014 included the results of operations for a marketing business that had been recently acquired by ETP and was sold effective April 1, 2014. 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 months ended March 31, 2013 included the results of Southern Union’s distribution operations.

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3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

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

• AmeriGas. In January 2014, ETP sold 9.2 million additional AmeriGas units. As of March 31, 2014, ETP owns 12.9 million AmeriGas common units representing an approximate 14% limited partner interest.

• 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 March 31,
	2014		2013
Revenue	$	1,819	$	1,511
Operating income	464		437
Net income	344		318

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.

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:

	Three Months Ended March 31,
	2014		2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	192	$	434
Net gains from subsidiary common unit transactions	$	603	$	10
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR and Hoover acquisitions	$	4,015	$	—
Long-term debt assumed in PVR acquisition	$	1,887	$	—

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5. INVENTORIES:

Inventories consisted of the following:

	March 31, 2014		December 31, 2013
Natural gas and NGLs	$	239	$	523
Crude oil	572		488
Refined products	466		597
Other	207		199
Total inventories	$	1,484	$	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, common unit price, dividend yield, and expected value, and are considered Level 3.

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 March 31, 2014 and December 31, 2013 was $27.64 billion and $23.97 billion, respectively. As of March 31, 2014 and December 31, 2013, the aggregate carrying amount of our consolidated debt obligations was $26.29 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.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2014 and December 31, 2013 based on inputs used to derive their fair values:

	Fair Value Measurements at March 31, 2014
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	4		$	—		$	4		$	—
Commodity derivatives:
Condensate — Forward Swaps	—			—			—			—
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	1			1			—			—
Fixed Swaps/Futures	118			118			—			—
NGLs — Forwards/Swaps	6			3			3			—
Power:
Forwards	5			—			5			—
Futures	1			1			—
Refined Products — Futures	1			1			—			—
Crude — Futures	1			1			—			—
Total commodity derivatives	138			130			8			—
Total assets	$	142		$	130		$	12		$	—
Liabilities:
Interest rate derivatives	$	(96	)	$	—		$	(96	)	$	—
Embedded derivatives in the Regency Preferred Units	(20		)	—			—			(20		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(3		)	(3		)	—			—
Swing Swaps IFERC	(4		)	(4		)	—			—
Fixed Swaps/Futures	(145		)	(135		)	(10		)	—
NGLs — Forwards/Swaps	(6		)	(5		)	(1		)	—
Power:
Forwards	(2		)	—			(2		)	—
Futures	(3		)	(3		)	—			—
Refined Products — Futures	(1		)	(1		)	—			—
Total commodity derivatives	(164		)	(151		)	(13		)	—
Total liabilities	$	(280	)	$	(151	)	$	(109	)	$	(20	)

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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 three months ended March 31, 2014. There were no transfers between the fair value hierarchy levels during the three months ended March 31, 2014 or 2013.

Balance, December 31, 2013	$	(19	)
Net unrealized loss included in other income (expense)	(1		)
Balance, March 31, 2014	$	(20	)

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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 March 31,
	2014			2013
Income from continuing operations	$	424		$	300
Less: Income from continuing operations attributable to noncontrolling interest	259			224
Income from continuing operations, net of noncontrolling interest	165			76
Less: Class D Unitholder’s interest in income from continuing operations	1			—
Income from continuing operations available to Limited Partners	$	164		$	76
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	557.7			559.9
Basic income from continuing operations per Limited Partner unit	$	0.30		$	0.14
Basic income from discontinued operations per Limited Partner unit	$	0.00		$	0.02
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	164		$	76
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1		)	—
Diluted income from continuing operations available to Limited Partners	$	163		$	76
Weighted average limited partner units	557.7			559.9
Dilutive effect of unconverted unit awards	0.7			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	558.4			559.9
Diluted income from continuing operations per Limited Partner unit	$	0.30		$	0.14
Diluted income from discontinued operations per Limited Partner unit	$	0.00		$	0.02

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8. DEBT OBLIGATIONS:

Our outstanding consolidated indebtedness was as follows:

	March 31, 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	450		450
ETE Senior Secured Term Loan due December 2, 2019	1,000		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	520		171
Subsidiary Indebtedness:
ETP Senior Notes	11,182		11,182
Regency Senior Notes	3,700		2,800
PVR Senior Notes	1,173		—
Transwestern Senior Unsecured Notes	870		870
Panhandle Senior Notes	1,085		1,085
Sunoco Senior Notes	965		965
Sunoco Logistics Senior Notes	1,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	—		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	606		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	950		200
Other Long-Term Debt	228		228
Unamortized discounts, premiums and fair value adjustments, net	367		301
Total	26,293		23,199
Less: Current maturities of long-term debt	1,388		637
Long-term debt and notes payable, less current maturities	$	24,905	$	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

On April 16, 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 March 31, 2014, there were $520 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $280 million. The weighted average interest rate on the total amount outstanding as of March 31, 2014 was 2.16%.

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 $450 million 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 $1.17 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 April 2014, Regency commenced a private offer to exchange any and all outstanding 8.375% Eagle Rock Senior Notes due 2019, of which $550 million in aggregate principal amount is outstanding, for 8.375% Senior Notes due 2019 to be issued by Regency with substantially the same economic terms, and is contingent upon the closing of the Eagle Rock Acquisition. On April 28, 2014, Regency extended the expiration date on this exchange offer to May 28, 2014, unless further extended or terminated.

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 March 31, 2014, the ETP Credit Facility had no 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.

As of March 31, 2014, the Regency Credit Facility had a balance outstanding of $606 million in revolving credit loans and approximately $21 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2014, which was reduced by any letters of credit, was approximately $873 million, and the weighted average interest rate on the total amount outstanding as of March 31, 2014 was 2.41%.

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 extended to $2.25 billion under certain conditions. As of March 31, 2014, the Sunoco Logistics Credit Facility had $950 million outstanding.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2014.

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9. EQUITY:

ETE Common Unit Activity

The change in ETE Common Units during the three months ended March 31, 2014 was as follows:

	Number of Units
Outstanding at December 31, 2013	559.9
Repurchase of units under buyback program	(8.1	)
Outstanding at March 31, 2014	551.8

From January through April, ETE repurchased approximately $750 million of ETE common units under 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 thethreemonths endedMarch 31, 2014, we recognized increases in partners’ capital of$603 million.

Sales of Common Units by ETP

ETP has entered into an Equity Distribution Agreement pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to an agreed-upon threshold. During thethree months ended March 31,2014, ETP received proceeds of$106 million, net of commissions of$1 million, from the issuance of units pursuant to the Equity Distribution Agreement, which proceeds were used for general partnership purposes. ETP also received $38 million, net of commissions, in April 2014 from the settlement of transactions initiated in March 2014 under this agreement. No amounts remain available to be issued under this agreement.

During the three months ended March 31,2014, distributions of$36 millionwere reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of0.7 millionETP Common Units. As ofMarch 31, 2014, a total of1.4 millionETP Common Units remain available to be issued under the existing registration statement for ETP’s Distribution Reinvestment Plan.

As discussed in Note 2, ETP redeemed and cancelled 18.7 million of its Common Units in connection with the Trunkline LNG Transaction.

Sales of Common Units by Regency

From time to time, Regency has sold Regency Common Units through an Equity Distribution Agreement, such sales of Regency Common Units are made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by Regency and the sales agent which is the counterparty to the equity distribution agreement. For the three months ended March 31,2014, Regency received net proceeds of $34 million from units issued pursuant to its Equity Distribution Agreement, which proceeds were used for general partnership purposes. As of March 31, 2014, no amounts remain available to be issued under its agreement.

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

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

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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	$	0.92000
March 31, 2014	May 5, 2014	May 15, 2014	0.93500

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 three months endedMarch 31, 2014, the net impact of these adjustments will result in a reduction of $26 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 current and future quarters:

	Total Year
2014 (remainder)	$	80
2015	51
2016	72
2017	50
2018	45
2019	35

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	$	0.47500
March 31, 2014	May 8, 2014	May 15, 2014	0.48000

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	$	0.66250
March 31, 2014	May 9, 2014	May 15, 2014	0.69500

On May 5, 2014, Sunoco Logistics’ Board of Directors declared a two-for-one split of Sunoco Logistics common units. The unit split will result 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 will be effective June 12, 2014. All Sunoco Logistics unit and per unit information is presented on a pre-split basis.

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Accumulated Other Comprehensive Income

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

	March 31, 2014			December 31, 2013
Available-for-sale securities	$	2		$	2
Foreign currency translation adjustment	(4		)	(1		)
Net loss on commodity related hedges	(4		)	(4		)
Actuarial gain related to pensions and other postretirement benefits	55			56
Equity investments, net	1			8
Subtotal	50			61
Amounts attributable to noncontrolling interest	(44		)	(52		)
Total AOCI, net of tax	$	6		$	9

10. INCOME TAXES:

The increase in the effective tax rate for the three months ended March 31, 2014 was primarily due to the Trunkline LNG Transaction (see Note 2). The Trunkline LNG Transaction, which was treated as a sale for tax purposes, resulted in $85 million of incremental income tax expense.

11. 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 March 31,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—		$	—		$	2		$	—
Interest cost	8			1			9			2
Expected return on plan assets	(11		)	(2		)	(15		)	(3		)
Actuarial (gain) loss amortization	(1		)	—			1			—
Settlement credits	(1		)	—			(2		)	—
	(5		)	(1		)	(5		)	(1		)
Regulatory adjustment	—			—			2			—
Net periodic benefit cost	$	(5	)	$	(1	)	$	(3	)	$	(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 MEG and NEG in 2013.

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12. 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

On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”).

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.

Commitments

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

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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056.  Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled $32 million and $33 million for the three months endedMarch 31, 2014 and 2013, respectively, which include contingent rentals totaling $3 million and $4 million in the three months ended March 31, 2014 and 2013, respectively.  During the three months ended March 31, 2014 and 2013, $8 million and $5 million, respectively, of rental expense was recovered through related sublease rental income.

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 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, injunctive relief, punitive damages and attorneys’ fees.

As of March 31, 2014, Sunoco is a defendant in seven cases, one of which was initiated by the State of New Jersey 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 and Puerto Rico cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting 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; however, it is reasonably possible that a loss may be realized. 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.

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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 to be 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. vs. 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. In addition, the jury may order interest and attorneys’ fees against Regency Marcellus of approximately $10 million. The jury found against Regency Marcellus on its counterclaims. Regency Marcellus has filed appropriate post-trial pleadings and is considering its appeal options.

Litigation Related to the Eagle Rock Acquisition

Two putative class action lawsuits challenging Regency’s acquisition of the Eagle Rock midstream assets are currently pending in federal district court in Houston, Texas. Both cases name Eagle Rock and its current directors, as well as Regency and a subsidiary (collectively, the “Regency Defendants”), 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 enjoin 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. The Regency Defendants 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

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insurance recoverable amounts related to the contingency.  As of March 31, 2014 and December 31, 2013, accruals of approximately $41 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.

No amounts have been recorded in our March 31, 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.

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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 identified as a potentially responsible party (“PRP”).  As ofMarch 31, 2014, Sunoco had been named as a PRP at39identified or potentially identifiable as “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.  Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

	March 31, 2014		December 31, 2013
Current	$	72	$	47
Non-current	339		356
Total environmental liabilities	$	411	$	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 March 31, 2014 and 2013, the Partnership recorded $8 million and $7 million, respectively, of expenditures related to environmental cleanup programs.

On June 29, 2011, the EPA finalized a rule under the CAA 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 DOT 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

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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 June 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.

13. 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

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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’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 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.

Derivatives are utilized in ETP’s other operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist.

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

	March 31, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	10,475,000		2014-2019	9,457,500		2014-2019
Basis Swaps IFERC/NYMEX (1)	(14,502,500	)	2014-2015	(487,500	)	2014-2017
Swing Swaps	—		—	1,937,500		2014-2016
Power (Megawatt):
Forwards	527,550		2014	351,050		2014
Futures	(1,161,949	)	2014	(772,476	)	2014
Options — Puts	(160,000	)	2014	(52,800	)	2014
Options — Calls	104,800		2014	103,200		2014
Crude (Bbls) — Futures	343,000		2014	103,000		2014
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	3,520,000		2014	570,000		2014
Swing Swaps IFERC	32,690,000		2014	(9,690,000	)	2014-2016
Fixed Swaps/Futures	(1,402,500	)	2014-2015	(8,195,000	)	2014-2015
Forward Physical Contracts	(5,483,135	)	2014-2015	5,668,559		2014-2015
Natural Gas Liquid (Bbls) — Forwards/Swaps	(904,000	)	2014	(1,133,600	)	2014
Refined Products (Bbls) — Futures	(123,000	)	2014	(280,000	)	2014
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	—		—	(7,352,500	)	2014
Fixed Swaps/Futures	(4,500,000	)	2014	(50,530,000	)	2014
Hedged Item — Inventory	4,500,000		2014	50,530,000		2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,375,000	)	2014	(1,825,000	)	2014
Fixed Swaps/Futures	(9,625,000	)	2014	(12,775,000	)	2014
Natural Gas Liquid (Bbls) — Forwards/Swaps	(765,000	)	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 losses of $4 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

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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. Speculative positions are prohibited under Regency’s policy.

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

	March 31, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(23,425,000	)	2014-2015	(24,455,000	)	2014-2015
Propane (Gallons) — Forwards/Swaps	(40,782,000	)	2014-2015	(52,122,000	)	2014-2015
NGLs (Barrels) — Forwards/Swaps	(330,000	)	2014	(438,000	)	2014
WTI Crude Oil (Barrels) — Forwards/Swaps	(392,000	)	2014	(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)	March 31, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	400	$	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	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 3.80% and receive a floating rate	275		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.

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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 March 31, 2014 would be $3 million, which would be reduced by $2 million, due to the netting feature.

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

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2014		December 31, 2013		March 31, 2014			December 31, 2013
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	1	$	3	$	(12	)	$	(18	)
	1		3		(12		)	(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	128	$	227	$	(139	)	$	(209	)
Commodity derivatives	60		43		(64		)	(48		)
Interest rate derivatives	4		47		(96		)	(95		)
Embedded derivatives in Regency Preferred Units	—		—		(20		)	(19		)
	192		317		(319		)	(371		)
Total derivatives	$	193	$	320	$	(331	)	$	(389	)

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

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
Derivatives in offsetting agreements:
OTC contracts	Price risk management asset (liability)	$	60		$	42		$	(56	)	$	(38	)
Broker cleared derivative contracts	Other current assets (liabilities)	188			264			(254		)	(318		)
		248			306			(310		)	(356		)
Offsetting agreements:
Counterparty netting	Price risk management asset (liability)	(52		)	(36		)	52			36
Payments on margin deposit	Other current assets (liabilities)	(10		)	(1		)	54			55
		(62		)	(37		)	106			91
Net derivatives with offsetting agreements		186			269			(204		)	(265		)
Derivatives without offsetting agreements		7			51			(127		)	(124		)
Total derivatives		$	193		$	320		$	(331	)	$	(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 March 31,
	2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(4	)	$	2
Total	$	(4	)	$	2

	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 March 31,
		2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(4	)	$	1
Total		$	(4	)	$	1

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	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended March 31,
		2014			2013
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(6	)	$	5
Total		$	(6	)	$	5

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2014			2013
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	7		$	(4	)
Commodity derivatives — Non-Trading	Cost of products sold	(6		)	(21		)
Commodity derivatives — Non-Trading	Deferred gas purchases	—			(5		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(2		)	6
Embedded derivatives	Other income	(1		)	(14		)
Total		$	(2	)	$	(38	)

14. 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.

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15. OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:

	March 31, 2014		December 31, 2013
Deposits paid to vendors	$	33	$	49
Prepaid expenses and other	246		263
Total other current assets	$	279	$	312

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	March 31, 2014		December 31, 2013
Interest payable	$	411	$	357
Customer advances and deposits	81		142
Accrued capital expenditures	224		260
Accrued wages and benefits	118		173
Taxes payable other than income taxes	237		211
Income taxes payable	240		4
Deferred income taxes	164		119
Deferred revenue	66		—
Other	417		412
Total accrued and other current liabilities	$	1,958	$	1,678

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16. REPORTABLE SEGMENTS:

As a result of the Trunkline 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 Trunkline LNG, including the operations of Trunkline 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, 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 Trunkline LNG prior to the Trunkline LNG Transaction, which was effective January 1, 2014. The Investment in Trunkline LNG segment reflected the results of operations of Trunkline LNG for all periods presented. Consequently, the results of operations of Trunkline LNG were reflected in two segments for the three months ended March 31, 2013. Therefore, the results of Trunkline LNG were included in eliminations for 2013.

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The following tables present financial information by segment:

	Three Months Ended March 31,
	2014			2013
Segment Adjusted EBITDA:
Investment in ETP	$	1,206		$	956
Investment in Regency	205			120
Investment in Trunkline LNG	48			45
Corporate and Other	(26		)	(6		)
Adjustments and Eliminations	(58		)	(63		)
Total	1,375			1,052
Depreciation and amortization	(373		)	(312		)
Interest expense, net of interest capitalized	(315		)	(310		)
Gain on sale of AmeriGas common units	70			—
Gains (losses) on interest rate derivatives	(2		)	6
Non-cash unit-based compensation expense	(20		)	(16		)
Unrealized gains (losses) on commodity risk management activities	(33		)	1
LIFO valuation adjustments	14			38
Equity in earnings of unconsolidated affiliates	104			90
Adjusted EBITDA related to unconsolidated affiliates	(210		)	(204		)
Adjusted EBITDA related to discontinued operations	(27		)	(40		)
Other, net	(14		)	(7		)
Income from continuing operations before income tax expense	$	569		$	298

	March 31, 2014			December 31, 2013
Total assets:
Investment in ETP	$	43,589		$	43,702
Investment in Regency	15,197			8,782
Investment in Trunkline LNG	1,221			1,338
Corporate and Other	757			720
Adjustments and Eliminations	(2,995		)	(4,212		)
Total	$	57,769		$	50,330

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	Three Months Ended March 31,
	2014			2013
Revenues:
Investment in ETP:
Revenues from external customers	$	12,212		$	10,837
Intersegment revenues	20			17
	12,232			10,854
Investment in Regency:
Revenues from external customers	806			535
Intersegment revenues	57			5
	863			540
Investment in Trunkline LNG:
Revenues from external customers	54			53
Adjustments and Eliminations	(69		)	(268		)
Total revenues	$	13,080		$	11,179

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 Trunkline LNG.

Investment in ETP

	Three Months Ended March 31,
	2014		2013
Intrastate Transportation and Storage	$	847	$	645
Interstate Transportation and Storage	295		323
Midstream	302		331
NGL Transportation and Services	801		346
Investment in Sunoco Logistics	4,452		3,457
Retail Marketing	5,008		5,217
All Other	527		535
Total revenues	12,232		10,854
Less: Intersegment revenues	20		17
Revenues from external customers	$	12,212	$	10,837

Investment in Regency

	Three Months Ended March 31,
	2014		2013
Gathering and Processing	$	793	$	486
Contract Services	63		49
Natural Resources	2		—
Corporate and Other	5		5
Total revenues	863		540
Less: Intersegment revenues	57		5
Revenues from external customers	$	806	$	535

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Investment in Trunkline LNG

Trunkline LNG’s revenue of $54 million and $53 million for the three months ended March 31, 2014 and 2013, respectively, were related to LNG terminalling.

17. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS

(unaudited)

	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16		$	8
Accounts receivable from related companies	6			5
Other current assets	1			—
Total current assets	23			13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,448			3,841
INTANGIBLE ASSETS, net	13			14
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	41			41
Total assets	$	4,534		$	3,918
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related companies	$	42		$	11
Interest payable	53			24
Accrued and other current liabilities	2			3
Total current liabilities	97			38
LONG-TERM DEBT, less current maturities	3,150			2,801
OTHER NON-CURRENT LIABILITIES	1			1
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	1,271			1,066
Class D Units	10			6
Accumulated other comprehensive income	6			9
Total partners’ capital	1,286			1,078
Total liabilities and partners’ capital	$	4,534		$	3,918

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STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2014			2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(31	)	$	(6	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(40		)	(64		)
Equity in earnings of unconsolidated affiliates	239			168
Other, net	—			(8		)
INCOME BEFORE INCOME TAXES	168			90
Income tax expense	—			—
NET INCOME	168			90
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	167		$	90

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STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2014			2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	229		$	182
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(7		)	—
Net cash used in investing activities	(7		)	—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	405			95
Principal payments on debt	(56		)	(65		)
Distributions to partners	(195		)	(179		)
Units repurchased under buyback program	(366		)	—
Debt issuance costs	(2		)	—
Net cash used in financing activities	(214		)	(149		)
INCREASE IN CASH AND CASH EQUIVALENTS	8			33
CASH AND CASH EQUIVALENTS, beginning of period	8			9
CASH AND CASH EQUIVALENTS, end of period	$	16		$	42

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

OVERVIEW

We directly and indirectly own equity interests in entities that are engaged in diversified energy-related services. At March 31, 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	26.3
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 Trunkline 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 Trunkline 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 Trunkline LNG, including the operations of Trunkline 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.

RECENT DEVELOPMENTS

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 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.

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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 common units issued to Hoover, (ii) $184 million in cash, and (iii) $2 million in asset retirement obligations assumed (the “Hoover Acquisition”). The Hoover Acquisition increases Regency’s fee-based revenue and expands 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’s Pending Acquisition of Eagle Rock

In December 2013, Regency entered into an agreement to purchase Eagle Rock’s midstream business for approximately $1.3 billion (the “Eagle Rock Acquisition”). This acquisition is expected to complement Regency’s core gathering and processing business and, when combined with the PVR Acquisition, is expected to further diversify Regency’s basin exposure in the Texas Panhandle, East Texas and South Texas. On April 29, 2014, Eagle Rock’s unitholders approved the Eagle Rock Acquisition. After receiving that approval, all significant closing conditions have been met with the exception of the Federal Trade Commission’s (“FTC”) antitrust approval. On April 30, 2014, Regency and Eagle Rock certified substantial compliance with the FTC in response to its Request for Additional Information and Documentary Material regarding the Eagle Rock Acquisition.  In order to facilitate the FTC’s review, Eagle Rock and Regency have agreed with the FTC to not close the proposed transaction before June 30, 2014, unless the FTC first closes its investigation.

Panhandle Merger

On January 10, 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 (the “Panhandle Merger”), with Panhandle as the surviving entity. 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 interest 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.

Trunkline LNG Transaction

On February 19, 2014, ETE and ETP completed the transfer to ETE of Trunkline LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, from ETP in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE. This transaction waseffective as of January 1, 2014.

ETE Term Loan

In April, ETE amended its Senior Secured Term Loan Agreement to increase the aggregate principal amount to $1.4 billion and used the proceeds from this $400 million increase to repay borrowings under our revolving credit facility and for general partnership purposes.

ETE Credit Facility Expansion

The Parent Company increased the capacity on its revolving credit facility to $1.2 billion through two steps, in February and May.

Susser Holdings Merger

On April 27, 2014, ETP entered into a definitive merger agreement whereby ETP plans to acquire Susser Holdings in a unit and cash transaction for total consideration valued at approximately $1.8 billion (the “Susser Merger”). By acquiring Susser Holdings, ETP will own the general partner interest and the incentive distribution rights in Susser Petroleum, approximately 11 million Susser Petroleum common units (representing approximately 50.2% of Susser Petroleum’s outstanding units), and Susser Holdings’ existing retail operations, consisting of 630 convenience store locations. The Susser Merger is expected to close in the third quarter of 2014, subject to approval of the shareholders of Susser Holdings and customary regulatory approvals.

ETE Unit Repurchase

From January through April, ETE repurchased approximately $750 million of ETE common units under its buyback program.

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Trunkline LNG FERC Application

Trunkline LNG Export, LLC and Trunkline LNG filed an application with the FERC, seeking authorization for its proposed new liquefaction facilities and modifications to Trunkline LNG’s existing terminal to facilitate the storage and subsequent export of LNG (the “Liquefaction Project”). In addition, Trunkline LNG filed an application with the FERC to convert Trunkline 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.

Results of Operations

We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, 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 Trunkline LNG prior to the Trunkline LNG Transaction, which was effective January 1, 2014. The Investment in Trunkline LNG segment reflected the results of operations of Trunkline LNG for all periods presented. Consequently, the results of operations of Trunkline LNG were reflected in two segments for the three months ended March 31, 2013. Therefore, the results of Trunkline LNG were included in eliminations for 2013.

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Consolidated Results

	Three Months Ended March 31,
	2014			2013			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,206		$	956		$	250
Investment in Regency	205			120			85
Investment in Trunkline LNG	48			45			3
Corporate and Other	(26		)	(6		)	(20		)
Adjustments and Eliminations	(58		)	(63		)	5
Total	1,375			1,052			323
Depreciation and amortization	(373		)	(312		)	(61		)
Interest expense, net of interest capitalized	(315		)	(310		)	(5		)
Gain on sale of AmeriGas common units	70			—			70
Gains (losses) on interest rate derivatives	(2		)	6			(8		)
Non-cash unit-based compensation expense	(20		)	(16		)	(4		)
Unrealized gains (losses) on commodity risk management activities	(33		)	1			(34		)
LIFO valuation adjustments	14			38			(24		)
Equity in earnings of unconsolidated affiliates	104			90			14
Adjusted EBITDA related to unconsolidated affiliates	(210		)	(204		)	(6		)
Adjusted EBITDA related to discontinued operations	(27		)	(40		)	13
Other, net	(14		)	(7		)	(7		)
Income from continuing operations before income tax expense	569			298			271
Income tax expense (benefit) from continuing operations	145			(2		)	147
Income from continuing operations	424			300			124
Income from discontinued operations	24			22			2
Net income	$	448		$	322		$	126

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

Depreciation and Amortization. Depreciation and amortization for the three months ended March 31, 2014 increased primarily due to the following:

• an increase of $29 million related to Regency primarily due to the completion of various organic growth projects, as well as the PVR and Hoover acquisitions; and

• additional depreciation and amortization related to assets placed in service at ETP.

Interest Expense, Net of Interest Capitalized. Interest expense for the three months ended March 31, 2014 increased primarily due to the following:

• incremental interest expense due to ETP’s issuance of $1.25 billion senior notes in January 2013 and the issuance by ETP of $1.5 billion of senior notes in September 2013; and

• an increase of $19 million related to Regency primarily due to its issuance of $600 million of senior notes in April 2013, $900 million of senior notes in February 2014 and $3 million in interest expense related to the senior notes assumed in the PVR acquisition; partially offset by

• a reduction of $24 million for the Parent Company 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, ETP recognized a gain on the sale of 9.2 million AmeriGas common units that were originally received in connection with the contribution of ETP’s propane business to AmeriGas in 2012. As of March 31, 2014, ETP held 12.9 million AmeriGas common units.

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Gains (Losses) on Interest Rate Derivatives. Losses on interest rate derivatives during the three months ended March 31, 2014 resulted from decreases in forward interest rates, which caused ETP’s forward-starting swaps to decrease in value, and a decrease in the aggregate notional amount outstanding. These swaps are marked to fair value for accounting purposes with changes in value recorded in earnings each period. Conversely, increases in forward interest rates resulted in gains on interest rate derivatives during the three months ended March 31, 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 months ended March 31, 2014 and 2013, respectively, for the inventory associated with Sunoco’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, PES and Citrus.

Adjusted EBITDA Related to Discontinued Operations. Amounts for the three months ended March 31, 2014 related to a marketing business that was sold by ETP effective April 1, 2014. Amounts for the three months ended March 31, 2013 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 (Benefit) From Continuing Operations. The increase in the effective tax rate for the three months ended March 31, 2014 was primarily due to the Trunkline LNG Transaction (see Note 2). The Trunkline LNG Transaction, which was treated as a sale for tax purposes, resulted in $85 million of incremental income tax expense.

Segment Operating Results

Investment in ETP

	Three Months Ended March 31,
	2014			2013			Change
Revenues	$	12,232		$	10,854		$	1,378
Cost of products sold	10,866			9,594			1,272
Gross margin	1,366			1,260			106
Unrealized losses (gains) on commodity risk management activities	29			(19		)	48
Operating expenses, excluding non-cash compensation expense	(315		)	(325		)	10
Selling, general and administrative, excluding non-cash compensation expense	(82		)	(127		)	45
LIFO valuation adjustments	(14		)	(38		)	24
Adjusted EBITDA related to unconsolidated affiliates	196			165			31
Adjusted EBITDA related to discontinued operations	27			40			(13		)
Other	(1		)	—			(1		)
Segment Adjusted EBITDA	$	1,206		$	956		$	250

Gross Margin. For the three months ended March 31, 2014 compared to the same period last year, gross margin increased $106 million, primarily due to:

• an increase in retail marketing gross margin of $69 million, which was primarily attributable to the acquisition of MACS in October 2013, favorable wholesale and retail distillate margins, and stronger retail gasoline margins;

• an increase in NGL transportation and services gross margin of $51 million for the three months ended March 31, 2014, primarily as a result of an increase in transportation margin from higher volumes transported from West Texas on Lone Star’s Gateway pipeline and an increase in NGL production, an increase in NGL processing and fractionation margin primarily due to higher volumes resulting from the startup of Lone Star’s second fractionator at Mont Belvieu, Texas in October 2013, and an increase in other margin due to higher NGL prices as a result of weather conditions;

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• an increase in ETP’s all other gross margin of $21 million due to favorable results from ETP’s commodity marketing businesses; partially offset by

• a decrease in Sunoco Logistics’ gross margin of $21 million primarily due to a decrease of approximately $100 million in margin from Sunoco Logistics’ crude oil acquisition and marketing business, which was driven by significantly contracted crude differentials, partially offset by an increase of approximately $36 million in revenues from Sunoco Logistics’ crude oil pipelines business, which was primarily attributable to expansion projects supporting the demand for West Texas crude oil; and

• a decrease in interstate transportation and storage’s revenue of $26 million primarily due to ETP’s deconsolidation of Trunkline LNG as of January 1, 2014.

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 months ended March 31, 2014, the unrealized losses were primarily driven by $18 million in losses from storage and non-storage related derivatives and $11 million in losses on the fair value adjustment to storage gas inventory. The three months ended March 31, 2013 included a gain of $20 million on the fair value adjustment to storage gas inventory.

Operating Expenses, Excluding Non-Cash Compensation Expense.For the three months ended March 31, 2014 compared to the same period last year, ETP’s operating expenses reflected the net impact of a $6 million increase in Sunoco Logistics’ operating expenses primarily due to increased utility expense associated with higher throughput volumes and increased environmental remediation costs, an $18 million increase in operating expenses for ETP’s retail marketing operations primarily due to the MACS acquisition, and a decrease of $29 million due to ETP’s deconsolidation of SUGS in 2013.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. ETP’s selling, general and administrative expense decreased primarily due to an increase in management fees paid by ETE, which were recorded as a reduction to selling, general and administrative within the Investment in ETP segment. 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. In addition, ETP’s selling, general and administrative expense decreased due to ETP’s deconsolidation of Trunkline LNG and SUGS, as well as overall cost cutting initiatives.

Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the three months ended March 31, 2014 consisted of the following:

	Three Months Ended March 31,
	2014		2013			Change
AmeriGas	$	51	$	97		$	(46	)
Citrus	68		62			6
FEP	19		18			1
Regency	27		—			27
PES	23		(21		)	44
Other	8		9			(1		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	196	$	165		$	31

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Investment in Regency

	Three Months Ended March 31,
	2014			2013			Change
Revenues	$	863		$	540		$	323
Cost of products sold	638			387			251
Gross margin	225			153			72
Unrealized losses on commodity risk management activities	4			18			(14		)
Operating expenses, excluding non-cash compensation expense	(76		)	(67		)	(9		)
Selling, general and administrative, excluding non-cash compensation expense	(33		)	(33		)	—
Adjusted EBITDA related to unconsolidated affiliates	75			63			12
Other	10			(14		)	24
Segment Adjusted EBITDA	$	205		$	120		$	85

Gross Margin. Regency’s gross margin increased for the three months ended March 31, 2014 compared to the same period last year primarily as a result of increased volumes in South and West Texas in Regency’s gathering and processing operations, as well as a $15 million contribution from the PVR and Hoover acquisitions.

Unrealized Losses on Commodity Risk Management Activities. Regency’s losses 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 months ended March 31, 2014 compared to the same periods last year as a result of organic growth in Regency’s gathering and processing operations in South and West Texas, as well as a $2 million increase related to the PVR acquisition.

Adjusted EBITDA Related to Unconsolidated Affiliates. Regency’s adjusted EBITDA attributable to unconsolidated affiliates increased primarily due to a $9 million increase in adjusted EBITDA attributable to Lone Star due to the commissioning of a new fractionator in late 2013, as well as an increase in marketing income due to a more favorable price environment in early 2014.

Other. Regency’s other income and deductions increased for the three months ended March 31, 2014 primarily due to a non-cash mark-to-market adjustment of the embedded derivative related to Regency’s Series A preferred units.

Investment in Trunkline LNG

	Three Months Ended March 31,
	2014			2013			Change
Revenues	$	54		$	53		$	1
Operating expenses, excluding non-cash compensation expense	(4		)	(5		)	1
Selling, general and administrative, excluding non-cash compensation expense	(2		)	(4		)	2
Other	—			1			(1		)
Segment Adjusted EBITDA	$	48		$	45		$	3

Amounts reflected above included comparative amounts for the three months ended March 31, 2013, which preceded ETE’s direct investment in Trunkline LNG effective January 1, 2014.

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

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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 Trunkline 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 Trunkline 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.

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
Intrastate transportation and storage	$	150	$	160	$	20	$	25
Interstate transportation and storage	50		60		110		120
Midstream	400		420		10		15
NGL transportation and services(1)	290		310		20		25
Investment in Sunoco Logistics	1,650		1,750		65		75
Retail marketing	125		155		50		60
All other (including eliminations)	80		90		10		20
Total projected capital expenditures	$	2,745	$	2,945	$	285	$	340

⁽¹⁾  ETP expects to receive capital contributions from Regency related to Regency’s 30% share of Lone Star of between $85 million and $110 million.

The assets used in ETP’s natural gas operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. From time to time ETP experiences increases in pipe costs due to a number of reasons, including but not limited to, replacing pipe caused by 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 capital requirements with cash flows from operating activities, borrowings under the ETP Credit Facility, the issuance of long-term debt or ETP Common Units or a combination thereof. Based on ETP’s current estimates, it expects to utilize capacity under the ETP Credit Facility, along with cash from operations, to fund its announced growth capital expenditures and working capital needs through the end of 2014; however, ETP may issue debt or equity securities prior to that time as it deems prudent to provide liquidity for new capital projects, to maintain investment grade credit ratings or other partnership purposes.

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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 $1.22 billion in growth capital expenditures, of which $860 million is expected to be invested in organic growth projects in the gathering and processing operations; $110 million is expected to be invested in growth capital expenditures in its NGL services operations; and $250 million is expected to be invested in growth capital expenditures in its contract services operations. In addition, Regency expects to invest $90 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 factors 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 and amortization expense and non-cash compensation expense. The increase in depreciation and amortization expense during the periods presented primarily resulted from the construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.

Three months ended March 31, 2014 compared to three months ended March 31, 2013. Cash provided by operating activities during 2014 was $829 million as compared to $330 million for 2013. Net income was $448 million and $322 million for 2014 and 2013, respectively. The difference between net income and the net cash provided by operating activities primarily consisted of non-cash items totaling $68 million and $204 million and changes in operating assets and liabilities of $246 million and $296 million for 2014 and 2013, respectively.

The non-cash activity in 2014 consisted primarily of depreciation and amortization of $373 million compared to $312 million in 2013.

Cash paid for interest, net of interest capitalized, was $307 million and $291 million for the three months endedMarch 31, 2014 and 2013, respectively.

Capitalized interest for the three months endedMarch 31, 2014 was $16 million.

Investing Activities

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

Three months ended March 31, 2014 compared to three months ended March 31, 2013. Cash used in investing activities during 2014 was $801 million as compared to $700 million for 2013. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2014 were $942 million, including changes in accruals of $1 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2013 of $761 million, including

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changes in accruals of $108 million. We paid cash for acquisitions of $214 million and received $381 million in cash from the sale of AmeriGas common units during the three months ended March 31, 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 based on increases in distribution rates, increases in the number of common units outstanding at our subsidiaries and increases in the number of our common units outstanding.

Three months ended March 31, 2014 compared to three months ended March 31, 2013. Cash used in financing activities during 2014 was $392 million as compared to cash provided by financing activities of $612 million for 2013. In 2014, our subsidiaries received $142 million in net proceeds from offerings of their common units as compared to $192 million in 2013. During 2014, we had a consolidated net increase in our debt level of $1.19 billion as compared to a net increase of $938 million for 2013. We paid distributions of $195 million and $179 million to our partners in 2014 and in 2013, respectively. Our subsidiaries paid distributions to noncontrolling interest of $397 million and $333 million in 2014 and 2013, respectively. We also paid $366 million to repurchase common units during the three months ended March 31, 2014 under our buyback program.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	March 31, 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	450		450
ETE Senior Secured Term Loan, due December 2, 2019	1,000		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	520		171
Subsidiary Indebtedness:
ETP	11,182		11,182
Regency	3,700		2,800
PVR	1,173		—
Transwestern	870		870
Panhandle	1,085		1,085
Sunoco	965		965
Sunoco Logistics	1,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	—		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	606		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	950		200
Other Long-Term Debt	228		228
Unamortized premiums and fair value adjustments, net	367		301
Total	26,293		23,199
Less: Current maturities of long-term debt	1,388		637
Long-term debt and notes payable, less current maturities	$	24,905	$	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.

ETE Term Loan Facility

On April 16, 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

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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 $450 million 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 $1.17 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 April 2014, Regency commenced a private offer to exchange any and all outstanding 8.375% Eagle Rock Senior Notes due 2019, of which $550 million in aggregate principal amount is outstanding, for 8.375% Senior Notes due 2019 to be issued by Regency with substantially the same economic terms, and is contingent upon the closing of the Eagle Rock Acquisition. On April 28, 2014, Regency extended the expiration date on this exchange offer to May 28, 2014, unless further extended or terminated.

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 March 31, 2014, we had $520 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $280 million. The weighted average interest rate on the total amount outstanding as of March 31, 2014 was 2.16%.

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 the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. As of March 31, 2014, the ETP Credit Facility had no 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 March 31, 2014, there was a balance outstanding under the Regency Credit Facility of $606 million in revolving credit loans and approximately $21 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2014, which was reduced by any letters of credit, was approximately $873 million, and the weighted average interest rate on the total amount outstanding as of March 31, 2014 was 2.41%.

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 extended to $2.25 billion under certain conditions. The credit facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The

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credit facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of March 31, 2014, the Sunoco Logistics Credit Facility had $950 million outstanding.

Covenants Related to Our Credit Agreements

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

• $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.

Additionally, Regency issued $900 million notional amount of 5.875% senior notes due March 1, 2022.

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

The total amounts of distributions declared and/or paid during the three months endedMarch 31, 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):

	Three Months Ended March 31,
	2014		2013
Limited Partners	$	195	$	181
Class D units	1		—
Total Parent Company distributions	$	196	$	181

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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 Trunkline LNG on February 19, 2014, Trunkline 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	26.3
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 the Parent Company received relating to its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is as follows:

	Three Months Ended March 31,
	2014			2013
Distributions from ETP:
Limited Partners	$	29		$	45
Class H Units held by ETE Holdings	50			—
General Partner interest	5			5
IDRs	168			156
IDR relinquishments related to previous transactions	(57		)	(31		)
Total distributions from ETP	195			175
Distributions from Regency:
Limited Partners	13			12
General Partner interest	1			1
IDRs	7			2
IDR relinquishment related to previous transaction	(1		)	—
Total distributions from Regency	20			15
Total distributions received from subsidiaries	$	215		$	190

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 three months endedMarch 31, 2014, the net impact of these adjustments will result in a reduction of $26 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)	$	80
2015	51
2016	72
2017	50
2018	45
2019	35

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.

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	$	0.92000
March 31, 2014	May 5, 2014	May 15, 2014	0.93500

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The total amounts of ETP distributions declared during the three months endedMarch 31, 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):

	Three Months Ended March 31,
	2014			2013
Limited Partners:
Common Units	$	297		$	286
Class H Units	50			—
General Partner interest	5			5
IDRs	168			156
IDR relinquishments related to previous transactions	(57		)	(31		)
Total ETP distributions	$	463		$	416

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	$	0.47500
March 31, 2014	May 8, 2014	May 15, 2014	0.48000

The total amounts of Regency distributions declared and/or paid during the three months endedMarch 31, 2014 and 2013 were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

	Three Months Ended March 31,
	2014			2013
Limited Partners	$	170		$	79
General Partner interest	1			1
IDRs	7			2
IDR relinquishment related to previous transaction	(1		)	—
Total Regency distributions	$	177		$	82

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.

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	$	0.66250
March 31, 2014	May 9, 2014	May 15, 2014	0.69500

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 will result 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 will be effective June 12, 2014. All Sunoco Logistics unit and per unit information is presented on a pre-split basis.

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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):

	Three Months Ended March 31,
	2014		2013
Limited Partners:
Common units held by public	$	49	$	40
Common units held by ETP	23		19
General Partner interest held by ETP	1		1
Incentive distributions held by ETP	38		25
Total distributions declared	$	111	$	85

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.

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 March 31, 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.

	March 31, 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	10,475,000		$	(1	)	$	5	9,457,500		$	3		$	5
Basis Swaps IFERC/NYMEX (1)	(14,502,500	)	2			—		(487,500	)	1			—
Swings Swaps IFERC	—		—			—		1,937,500		1			—
Power (Megawatt):
Forwards	527,550		3			2		351,050		1			1
Futures	(1,161,949	)	(1		)	5		(772,476	)	—			2
Options — Puts	(160,000	)	—			1		(52,800	)	—			—
Options — Calls	104,800		—			—		103,200		—			—
Crude (Bbls) — Futures	343,000		—			4		103,000		—			1
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	3,520,000		—			—		570,000		—			—
Swing Swaps IFERC	32,690,000		(2		)	1		(9,690,000	)	1			—
Fixed Swaps/Futures	(1,402,500	)	(9		)	3		(8,195,000	)	13			3
Forward Physical Contracts	(5,483,135	)	—			2		5,668,559		(1		)	2
Natural Gas Liquid (Bbls) – Forwards/Swaps	(904,000	)	(2		)	8		(1,133,600	)	—			17
Refined Products (Bbls) — Futures	(123,000	)	—			7		(280,000	)	—			3
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	—		—			—		(7,352,500	)	—			—
Fixed Swaps/Futures	(4,500,000	)	(4		)	2		(50,530,000	)	(11		)	23
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,375,000	)	—			—		(1,825,000	)	—			—
Fixed Swaps/Futures	(9,625,000	)	(5		)	4		(12,775,000	)	(3		)	6
Natural Gas Liquid (Bbls) – Forwards/Swaps	(765,000	)	1			4		(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.

	March 31, 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	(23,425,000	)	$	(8	)	$	10	(24,455,000	)	$	(2	)	$	10
Propane (Gallons) — Forwards/Swaps	(40,782,000	)	(1		)	4		(52,122,000	)	(3		)	6
NGLs (Barrels) — Forwards/Swaps	(330,000	)	3			2		(438,000	)	1			2
WTI Crude Oil (Barrels) — Forwards/Swaps	(392,000	)	(2		)	4		(521,000	)	(1		)	5

Interest Rate Risk

As of March 31, 2014, we and our subsidiaries had $3.72 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $37 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 March 31, 2014 and December 31, 2013 (dollars in millions), none of which are designated as hedges for accounting purposes:

			Notional Amount Outstanding
Entity	Term	Type(1)	March 31, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	400	$	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	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 3.80% and receive a floating rate	275		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.

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⁽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 $127 million as of March 31, 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 $3 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 March 31, 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 on its acquisition of Hoover on February 3, 2014 and its acquisition of PVR on March 21, 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 March 31, 2014.

None of the changes resulting from the Hoover Acquisition and the PVR Acquisition were in response to any identified deficiency or weakness in our internal control over financial reporting other than changes resulting from these acquisitions.

There have been no changes in our internal controls, other than those resulting from the Hoover and PVR acquisitions, over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2013 and Note 12 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Partners, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table discloses purchases of ETE Common Units made by us or on our behalf in the quarter ended March 31, 2014:

Period	Total Number of Units Purchased	Average Price Paid per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs (1)	Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
January 2014	734,400	$	40.72	734,400	$	970,411,063
February 2014	960,800	40.72		960,800	931,267,749
March 2014	6,451,100	45.83		6,451,100	633,596,891
Total	8,146,300			8,146,300

⁽¹⁾  The ETE $1 billion buyback program was announced on December 23, 2013. The Partnership may commence, suspend or discontinue purchases of common units under this authorization at any time or periodically without prior notice and any common units repurchased will be canceled.

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ITEM 6. EXHIBITS

The exhibits listed below are filed as part of this report:

	Exhibit Number	Description
(*)	10.1	Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.
	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

*	Indicates exhibit incorporated by reference to Energy Transfer Equity, L.P. Current Report on Form 8-K filed on February 19, 2014.
**	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:	May 8, 2014	By:	/s/ Jamie Welch
			Jamie Welch
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)

62

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 8, 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: May 8, 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 March 31, 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; and

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

Date: May 8, 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 March 31, 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; and

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

Date: May 8, 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.

XML

Operations And Organization Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 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%
Holdco [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
Trunkline LNG [Member]
LNG Storage Capacity	9.0
ETP [Member] | Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	70.00%
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	$ 530	$ 514

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Equity Table - Quarterly Distributions of Available Cash (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Parent Company [Member]
Distribution Made to Limited Partner, Date of Record	May 05, 2014	Feb. 07, 2014
Distribution Made to Limited Partner, Distribution Date	May 19, 2014	Feb. 19, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.35875	$ 0.34625
ETP [Member]
Distribution Made to Limited Partner, Date of Record	May 05, 2014	Feb. 07, 2014
Distribution Made to Limited Partner, Distribution Date	May 15, 2014	Feb. 14, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.93500	$ 0.92000
Regency [Member]
Distribution Made to Limited Partner, Date of Record	May 08, 2014	Feb. 07, 2014
Distribution Made to Limited Partner, Distribution Date	May 15, 2014	Feb. 14, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.480	$ 0.475
Sunoco Logistics [Member]
Distribution Made to Limited Partner, Date of Record	May 09, 2014	Feb. 10, 2014
Distribution Made to Limited Partner, Distribution Date	May 15, 2014	Feb. 14, 2014
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.69500	$ 0.66250

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Fair Value Measurements Table - Reconciliation of Level 3 Derivatives (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Level 3 [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Level 3 [Member] Fair Value, Measurements, Recurring [Member]
Balance, December 31, 2013		$ (20)	$ (19)
Net unrealized loss included in other income (expense)	1
Balance, March 31, 2014		$ (20)	$ (19)

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Reportable Segments Narrative (Details) (Regency [Member], Lone Star L.L.C. [Member])	3 Months Ended
	Mar. 31, 2014
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%

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Equity Table - IDR Schedule (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Relinquishment of Rights of Incentive Distributions	$ 26	$ 35	$ 45	$ 50	$ 72	$ 51	$ 80

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Fair Value Measurements Narrative (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair Value Measurements [Abstract]
Debt obligations, fair value	$ 27,640	$ 23,970
Long-term Debt	$ 26,293	$ 23,199

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—		$	—		$	2		$	—
Interest cost	8			1			9			2
Expected return on plan assets	(11		)	(2		)	(15		)	(3		)
Actuarial (gain) loss amortization	(1		)	—			1			—
Settlement credits	(1		)	—			(2		)	—
	(5		)	(1		)	(5		)	(1		)
Regulatory adjustment	—			—			2			—
Net periodic benefit cost	$	(5	)	$	(1	)	$	(3	)	$	(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 MEG and NEG in 2013.

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Reportable Segments Table - Revenues (External and Intersegment) by Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Intersegment Revenues	$ 13,080	$ 11,179
Investment In ETP [Member]
Intersegment Revenues	12,232	10,854
Investment In Regency [Member]
Intersegment Revenues	863	540
Adjustments And Eliminations [Member]
Intersegment Revenues	(69)	(268)
Intersegment [Member] | Investment In ETP [Member]
Intersegment Revenues	20	17
Intersegment [Member] | Investment In Regency [Member]
Intersegment Revenues	57	5
External Customers [Member] | Investment In ETP [Member]
Intersegment Revenues	12,212	10,837
External Customers [Member] | Investment In Regency [Member]
Intersegment Revenues	806	535
External Customers [Member] | Investment in Trunkline LNG [Member]
Intersegment Revenues	$ 54	$ 53

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Income Taxes (Details) (Trunkline LNG [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Trunkline LNG [Member]
Incremental Income Tax Related to Transaction	$ 85

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Supplemental Financial Statement Information Schedule of Statements of Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$ (148)	$ (157)
Interest expense	(315)	(310)
Equity in earnings of unconsolidated affiliates	104	90
Losses on interest rate derivatives	(2)	6
Other, net	2	(19)
Income tax expense (benefit)	145	(2)
NET INCOME ATTRIBUTABLE TO PARTNERS	168	90
GENERAL PARTNER’S INTEREST IN NET INCOME	0	0
Class D Unitholder's interest in Net Income	1	0
LIMITED PARTNERS' INTEREST IN NET INCOME	167	90
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	(31)	(6)
Interest expense	(40)	(64)
Equity in earnings of unconsolidated affiliates	239	168
Other, net	0	(8)
INCOME BEFORE INCOME TAXES	168	90
Income tax expense (benefit)	0	0
NET INCOME ATTRIBUTABLE TO PARTNERS	168	90
GENERAL PARTNER’S INTEREST IN NET INCOME	0	0
Class D Unitholder's interest in Net Income	1	0
LIMITED PARTNERS' INTEREST IN NET INCOME	$ 167	$ 90

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Supplemental Financial Statement Information Schedule Of Statements of Cash Flows (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 829	$ 330
Net cash used in investing activities	(801)	(700)
Proceeds received in (paid for) acquisitions and other transactions, net	(214)	0
Proceeds from borrowings	3,170	2,899
Repayments of long-term debt	(1,977)	(1,961)
Distributions to partners	195	179
Units repurchased	366	0
Debt issuance costs	(17)	(16)
Net cash used in financing activities	392	612
INCREASE IN CASH AND CASH EQUIVALENTS	420	242
CASH AND CASH EQUIVALENTS, beginning of period	590	372
CASH AND CASH EQUIVALENTS, end of period	1,010	614
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	229	182
Net cash used in investing activities	(7)	0
Contributions to unconsolidated affiliate	(7)	0
Proceeds from borrowings	405	95
Repayments of long-term debt	(56)	(65)
Distributions to partners	(195)	(179)
Units repurchased	(366)	0
Debt issuance costs	(2)	0
Net cash used in financing activities	(214)	(149)
INCREASE IN CASH AND CASH EQUIVALENTS	8	33
CASH AND CASH EQUIVALENTS, beginning of period	8	9
CASH AND CASH EQUIVALENTS, end of period	$ 16	$ 42

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Reportable Segments Table - Segment Adjusted EBITDA (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Sep. 30, 2012
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 1,375	$ 1,052
Depreciation and amortization	(373)	(312)
Interest Expense, net of interest capitalized	(315)	(310)
Gain on sale of AmeriGas common units	70	0	0
Gains (losses) on interest rate derivatives	(2)	6
Non-cash unit-based compensation expense	(20)	(16)
Unrealized Gain (Loss) on commodity risk management activities	(33)	1
LIFO valuation adjustment	14	38
Equity in earnings of unconsolidated affiliates	104	90
Adjusted EBITDA related to unconsolidated affiliates	(210)	(204)
Adjusted EBITDA related to discontinued operations	(27)	(40)
Other	(14)	(7)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	569	298
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,206	956
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	205	120
Investment in Trunkline LNG [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	48	45
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(26)	(6)
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ (58)	$ (63)

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Acquisitions Acquisition Tables (Tables)

3 Months Ended

Mar. 31, 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 months ended March 31, 2014 and 2013 are presented as if the PVR and Hoover 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.

	Three Months Ended March 31,
	2014		2013
Revenues	$	13,362	$	11,449
Net income attributable to partners	161		84
Basic net income per Limited Partner unit	$	0.29	$	0.15
Diluted net income per Limited Partner unit	$	0.29	$	0.15

PVR Acquisition [Member]

Business Acquisition [Line Items]

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

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

	March 21, 2014
Current assets	$	150
Plant, property and equipment	2,687
Investment in unconsolidated affiliates	62
Goodwill and intangible assets	3,079
Total assets acquired	$	5,978
Current liabilities	166
Long-term debt	1,887
Asset retirement obligations	3
Net assets acquired	$	3,922

Hoover Midstream Acquisition [Member]

Business Acquisition [Line Items]

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

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

	February 3, 2014
Current assets	$	5
Property, plant and equipment	114
Goodwill and intangible assets	181
Total assets acquired	$	300
Current liabilities	5
Asset retirement obligations	2
Net assets acquired	$	293

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Debt Obligations Narrative (Details) (USD $)										1 Months Ended
	Mar. 31, 2014 ETP [Member]	Dec. 31, 2013 ETP [Member]	Mar. 31, 2014 Sunoco Logistics [Member]	Dec. 31, 2013 Sunoco Logistics [Member]	Mar. 31, 2014 Regency [Member]	Dec. 31, 2013 Regency [Member]	Mar. 31, 2014 PVR [Member]	Dec. 31, 2013 PVR [Member]	Mar. 31, 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]	May 01, 2014 ETE Senior Secured Revolving Credit Facilities [Member]	Mar. 31, 2014 ETE Senior Secured Revolving Credit Facilities [Member]	Mar. 31, 2014 5.30% Senior Notes due April 2024 [Member] Sunoco Logistics [Member]	Mar. 31, 2014 4.25% Senior Notes due April 2024 [Member] Sunoco Logistics [Member]	Mar. 31, 2014 ETE 7.5% Senior Notes due 2020 [Member]	Mar. 31, 2014 5.875% Senior Notes due March 1, 2022 [Member] Regency [Member]	Mar. 31, 2014 8.25% Senior Notes due April 15, 2015 [Member] PVR [Member]	Mar. 31, 2014 6.5% Senior Notes due May 15, 2021 [Member] PVR [Member]	Mar. 31, 2014 8.375% Senior Notes due June 1, 2020 [Member] PVR [Member]	Apr. 30, 2014 8.375% Senior Notes due June 1, 2020 [Member] Eagle Rock [Member]	Mar. 31, 2014 ETP Revolving Credit Facility, due October 2017 [Member] ETP [Member]	Mar. 31, 2014 Regency Credit Facility [Member]	Mar. 31, 2014 Sunoco Logistics $1.5 billion Revolving Credit Facility, due November 1, 2018 [Member] Sunoco Logistics [Member]	Mar. 31, 2014 Uncommitted Incremental Facility [Member] Regency Credit Facility [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
Repayments of Lines of Credit										400,000,000
Line of Credit Facility, Amount Outstanding																					0	606,000,000	950,000,000
Line of Credit Facility, Remaining Borrowing Capacity												280,000,000										873,000,000
Debt, Weighted Average Interest Rate												2.16%										2.41%
Letters of Credit Outstanding, Amount																						21,000,000
Senior Notes	11,182,000,000	11,182,000,000	1,975,000,000	2,150,000,000	3,700,000,000	2,800,000,000	1,173,000,000	0					700,000,000	300,000,000		900,000,000	300,000,000	400,000,000	473,000,000	550,000,000
Debt Instrument, Interest Rate, Stated Percentage									5.875%				5.30%	4.25%	7.50%	5.875%	8.25%	6.50%	8.375%	8.375%
Line of Credit Facility, Maximum Borrowing Capacity																						$ 1,500,000,000	$ 2,250,000,000	$ 500,000,000

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Investments in Affiliates Narrative (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended
	Jan. 31, 2014	Mar. 31, 2014	Mar. 31, 2013
Schedule of Equity Method Investments [Line Items]
AmeriGas common units sold by ETP	9.2
Proceeds from ETP's sale of AmeriGas common units		$ 381	$ 0
AmeriGas [Member]
Schedule of Equity Method Investments [Line Items]
Investment Owned, Balance, Shares		12.9
Interest ownership		14.00%
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership		50.00%
FGT [Member]
Schedule of Equity Method Investments [Line Items]
Percentage Ownership Operating Facility		100.00%
Fayetteville Express Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership		50.00%
RIGS Haynesville Partnership Co. [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership		49.99%
Midcontinent Express Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership		50.00%

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Supplemental Financial Statement Information Table - Balance Sheets (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
Cash and cash equivalents	$ 1,010	$ 590	$ 614	$ 372
Accounts receivable from related companies	40	63
Other current assets	279	312
Total current assets	7,516	6,536
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,818	4,014
INTANGIBLE ASSETS, net	5,132	2,264
GOODWILL	6,216	5,894
OTHER NON-CURRENT ASSETS, net	971	922
Total assets	57,769	50,330
Accounts payable	4,272	3,834
Accounts payable to related companies	10	14
Interest payable	411	357
Price risk management liabilities	70	53
Accrued and other current liabilities	1,958	1,678
Current maturities of long-term debt	1,388	637
Total current liabilities	8,091	6,500
LONG-TERM DEBT, less current maturities	24,905	22,562
PREFERRED UNITS OF SUBSIDIARY	32	32
OTHER NON-CURRENT LIABILITIES	1,024	1,019
COMMITMENTS AND CONTINGENCIES
General Partner	(1)	(3)
Limited Partners	1,271	1,066
Class D Units	10	6
Accumulated other comprehensive income	6	9
Total partners’ capital	1,286	1,078
Total liabilities and equity	57,769	50,330
Parent Company [Member]
Cash and cash equivalents	16	8	42	9
Accounts receivable from related companies	6	5
Other current assets	1	0
Total current assets	23	13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,448	3,841
INTANGIBLE ASSETS, net	13	14
GOODWILL	9	9
OTHER NON-CURRENT ASSETS, net	41	41
Total assets	4,534	3,918
Accounts payable to related companies	42	11
Interest payable	53	24
Accrued and other current liabilities	2	3
Total current liabilities	97	38
LONG-TERM DEBT, less current maturities	3,150	2,801
OTHER NON-CURRENT LIABILITIES	1	1
COMMITMENTS AND CONTINGENCIES
General Partner	(1)	(3)
Limited Partners	1,271	1,066
Class D Units	10	6
Accumulated other comprehensive income	6	9
Total partners’ capital	1,286	1,078
Total liabilities and equity	$ 4,534	$ 3,918

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Reportable Segments (Tables)

3 Months Ended

Mar. 31, 2014

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

Investment in Trunkline LNG

Operating Segments [Member]

Financial Information By Segment

	Three Months Ended March 31,
	2014			2013
Segment Adjusted EBITDA:
Investment in ETP	$	1,206		$	956
Investment in Regency	205			120
Investment in Trunkline LNG	48			45
Corporate and Other	(26		)	(6		)
Adjustments and Eliminations	(58		)	(63		)
Total	1,375			1,052
Depreciation and amortization	(373		)	(312		)
Interest expense, net of interest capitalized	(315		)	(310		)
Gain on sale of AmeriGas common units	70			—
Gains (losses) on interest rate derivatives	(2		)	6
Non-cash unit-based compensation expense	(20		)	(16		)
Unrealized gains (losses) on commodity risk management activities	(33		)	1
LIFO valuation adjustments	14			38
Equity in earnings of unconsolidated affiliates	104			90
Adjusted EBITDA related to unconsolidated affiliates	(210		)	(204		)
Adjusted EBITDA related to discontinued operations	(27		)	(40		)
Other, net	(14		)	(7		)
Income from continuing operations before income tax expense	$	569		$	298

Assets Segments [Member]

Financial Information By Segment

	March 31, 2014			December 31, 2013
Total assets:
Investment in ETP	$	43,589		$	43,702
Investment in Regency	15,197			8,782
Investment in Trunkline LNG	1,221			1,338
Corporate and Other	757			720
Adjustments and Eliminations	(2,995		)	(4,212		)
Total	$	57,769		$	50,330

Sales Revenue, Segment [Member]

Financial Information By Segment

	Three Months Ended March 31,
	2014			2013
Revenues:
Investment in ETP:
Revenues from external customers	$	12,212		$	10,837
Intersegment revenues	20			17
	12,232			10,854
Investment in Regency:
Revenues from external customers	806			535
Intersegment revenues	57			5
	863			540
Investment in Trunkline LNG:
Revenues from external customers	54			53
Adjustments and Eliminations	(69		)	(268		)
Total revenues	$	13,080		$	11,179

Investment In ETP [Member]

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

Investment in ETP

	Three Months Ended March 31,
	2014		2013
Intrastate Transportation and Storage	$	847	$	645
Interstate Transportation and Storage	295		323
Midstream	302		331
NGL Transportation and Services	801		346
Investment in Sunoco Logistics	4,452		3,457
Retail Marketing	5,008		5,217
All Other	527		535
Total revenues	12,232		10,854
Less: Intersegment revenues	20		17
Revenues from external customers	$	12,212	$	10,837

Investment In Regency [Member]

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

Investment in Regency

	Three Months Ended March 31,
	2014		2013
Gathering and Processing	$	793	$	486
Contract Services	63		49
Natural Resources	2		—
Corporate and Other	5		5
Total revenues	863		540
Less: Intersegment revenues	57		5
Revenues from external customers	$	806	$	535

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Equity Narrative (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		4 Months Ended	12 Months Ended						3 Months Ended				1 Months Ended	3 Months Ended		1 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	May 01, 2014	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2014 ETP [Member]	Mar. 31, 2014 ETP [Member] Distribution Reinvestment Plan [Member]	Apr. 30, 2014 Regency [Member]	Mar. 31, 2014 Regency [Member]	Apr. 30, 2014 Equity distribution agreement [Member] ETP [Member]	Mar. 31, 2014 Equity distribution agreement [Member] ETP [Member]	Mar. 31, 2014 Equity distribution agreement [Member] Regency [Member]	Feb. 28, 2014 Hoover Midstream Acquisition [Member] Common Units [Member] Regency [Member]	Mar. 21, 2014 PVR Acquisition [Member] Common Units [Member] Regency [Member]
Units repurchased under buyback program	$ (366)		$ 750
Equity Distribution Reinvestment Program, Capacity, Shares											1,400,000
Gain on Sale of Previously Unissued Stock by Subsidiary	603	10
Partners' Capital Account, Units, Redeemed										(18,700,000)
Equity Distribution Agreement Program, Capacity Remaining, Dollar Amount												400	0
Relinquishment of Rights of Incentive Distributions	26			35	45	50	72	51	80
Proceeds from Issuance of Common Stock														38	106	34
Fees and Commissions															1
Stock Issued During Period, Value, Dividend Reinvestment Plan										$ 36
Stock Issued During Period, Shares, Dividend Reinvestment Plan										700,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares																	4,040,471	140,400,000

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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
	Mar. 31, 2014	Mar. 31, 2013
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ (4)	$ 1
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	(6)	5
Amount of Gain/(Loss) Recognized in Income on Derivatives	(2)	(38)
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	7	(4)
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	(4)	1
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	(6)	5
Amount of Gain/(Loss) Recognized in Income on Derivatives	(6)	(21)
Commodity Derivatives [Member] | Deferred Gas Purchases [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	0	(5)
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(2)	6
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (1)	$ (14)

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Price Risk Management Assets And Liabilities Narrative (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
ETP [Member]
Expected gains (losses) related to derivatives to be reclassified into earnings over next year related to amounts currently reported an AOCI	$ (4)
Regency [Member]
Notional Amount of Credit Risk Derivatives	3
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ 2

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Fair Value Measurements Table - Fair Value of Financial Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Liabilities, Fair Value Disclosure, Recurring	$ (280)	$ (347)
Fair Value, Inputs, Level 1 [Member]
Liabilities, Fair Value Disclosure, Recurring	(151)	(215)
Fair Value, Inputs, Level 2 [Member]
Liabilities, Fair Value Disclosure, Recurring	(109)	(113)
Level 3 [Member]
Liabilities, Fair Value Disclosure, Recurring	(20)	(19)
Fair Value, Measurements, Recurring [Member]
Interest Rate Derivative Assets, at Fair Value	4	47
Price Risk Derivative Assets, at Fair Value	138	231
Assets, Fair Value Disclosure	142	278
Interest Rate Derivative Liabilities, at Fair Value	96	95
Embedded Derivative, Fair Value of Embedded Derivative Liability	20	19
Price Risk Derivative Liabilities, at Fair Value	164	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	130	217
Assets, Fair Value Disclosure	130	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	151	215
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Interest Rate Derivative Assets, at Fair Value	4	47
Price Risk Derivative Assets, at Fair Value	8	14
Assets, Fair Value Disclosure	12	61
Interest Rate Derivative Liabilities, at Fair Value	96	95
Embedded Derivative, Fair Value of Embedded Derivative Liability	0	0
Price Risk Derivative Liabilities, at Fair Value	13	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	20	19
Price Risk Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Forward Swaps [Member]
Trading Securities	0
Price Risk Derivative Liabilities, at Fair Value		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Inputs, Level 1 [Member] | Forward Swaps [Member]
Trading Securities	0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Fair Value, Inputs, Level 2 [Member] | Forward Swaps [Member]
Trading Securities	0
Price Risk Derivative Liabilities, at Fair Value		1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 3 [Member] | Forward Swaps [Member]
Trading Securities	0
Price Risk Derivative Liabilities, at Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]
Price Risk Derivative Assets, at Fair Value	5	5
Price Risk Derivative Liabilities, at Fair Value	3	4
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Price Risk Derivative Assets, at Fair Value	1	8
Price Risk Derivative Liabilities, at Fair Value	4	6
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Price Risk Derivative Assets, at Fair Value	118	203
Price Risk Derivative Liabilities, at Fair Value	145	206
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value		(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	5	5
Price Risk Derivative Liabilities, at Fair Value	3	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	4	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	118	201
Price Risk Derivative Liabilities, at Fair Value	135	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
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	0	7
Price Risk Derivative Liabilities, at Fair Value	0	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	0	2
Price Risk Derivative Liabilities, at Fair Value	10	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)
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
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Forward Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value	(1)	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	1	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	(1)	(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	1	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	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
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Forward Swaps [Member]
Price Risk Derivative Liabilities, at Fair Value	0	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
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Inputs, Level 1 [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Fair Value, Inputs, Level 2 [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Crude [Member] | Level 3 [Member] | Future [Member]
Price Risk Derivative Assets, at Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	5	3
Price Risk Derivative Liabilities, at Fair Value	(2)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member]
Trading Securities	1
Trading Liabilities, Fair Value Disclosure	3
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
Trading Liabilities, Fair Value Disclosure	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed Swaps/Futures [Member]
Trading Securities	1
Trading Liabilities, Fair Value Disclosure	3
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	5	3
Price Risk Derivative Liabilities, at Fair Value		(1)
Trading Liabilities, Fair Value Disclosure	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed Swaps/Futures [Member]
Trading Securities	0
Trading Liabilities, Fair Value Disclosure	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
Trading Liabilities, Fair Value Disclosure	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Trading Securities
Trading Liabilities, Fair Value Disclosure	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]
Price Risk Derivative Assets, at Fair Value	6	7
Price Risk Derivative Liabilities, at Fair Value	6	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	3	5
Price Risk Derivative Liabilities, at Fair Value	5	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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Investments in Affiliates

3 Months Ended

Mar. 31, 2014

INVESTMENTS IN UNCONSOLIDATED AFFILIATES [Abstract]

Investments in and Advances to Affiliates

INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

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

• AmeriGas. In January 2014, ETP sold 9.2 million additional AmeriGas units. As of March 31, 2014, ETP owns 12.9 million AmeriGas common units representing an approximate 14% limited partner interest.

• 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 March 31,
	2014		2013
Revenue	$	1,819	$	1,511
Operating income	464		437
Net income	344		318

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.

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Price Risk Management Assets And Liabilities Table - Outstanding Commodity-Related Derivatives (Details)	Mar. 31, 2014 barrels	Dec. 31, 2013 barrels
Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]
Notional Volume	343,000	103,000
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Call Option [Member] | ETP [Member]
Notional Volume	104,800	103,200
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	527,550	351,050
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Future [Member] | ETP [Member]
Notional Volume	(1,161,949)	(772,476)
Maximum Term Of Commodity Derivatives	2014	2014
Mark-To-Market Derivatives [Member] | Power [Member] | Options - Puts [Member] | ETP [Member]
Notional Volume	(160,000)	(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	(123,000)	(280,000)
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(14,502,500)	(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	10,475,000	9,457,500
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	2019	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	(904,000)	(1,133,600)
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	(392,000)	(521,000)
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas Liquids [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	(330,000)	(438,000)
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	3,520,000	570,000
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC [Member] | ETP [Member]
Notional Volume	32,690,000	(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	(1,402,500)	(8,195,000)
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Notional Volume	(23,425,000)	(24,455,000)
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Contracts [Member] | ETP [Member]
Notional Volume	(5,483,135)	5,668,559
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	(40,782,000)	(52,122,000)
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	2015	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] | 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	0	(7,352,500)
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(4,500,000)	(50,530,000)
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Hedged Item - Inventory (MMBtu) [Member] | ETP [Member]
Notional Volume	4,500,000	50,530,000
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Cash Flow Hedging [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	(765,000)	(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	(1,375,000)	(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	(9,625,000)	(12,775,000)
Maximum Term Of Commodity Derivatives	2014	2014

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Investments in Affiliates Table - Selected I/S Data (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Schedule of Equity Method Investments [Line Items]
Revenue	$ 1,819	$ 1,511
Operating income	464	437
Net income	$ 344	$ 318

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2014 and December 31, 2013 based on inputs used to derive their fair values:

	Fair Value Measurements at March 31, 2014
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	4		$	—		$	4		$	—
Commodity derivatives:
Condensate — Forward Swaps	—			—			—			—
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	1			1			—			—
Fixed Swaps/Futures	118			118			—			—
NGLs — Forwards/Swaps	6			3			3			—
Power:
Forwards	5			—			5			—
Futures	1			1			—
Refined Products — Futures	1			1			—			—
Crude — Futures	1			1			—			—
Total commodity derivatives	138			130			8			—
Total assets	$	142		$	130		$	12		$	—
Liabilities:
Interest rate derivatives	$	(96	)	$	—		$	(96	)	$	—
Embedded derivatives in the Regency Preferred Units	(20		)	—			—			(20		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(3		)	(3		)	—			—
Swing Swaps IFERC	(4		)	(4		)	—			—
Fixed Swaps/Futures	(145		)	(135		)	(10		)	—
NGLs — Forwards/Swaps	(6		)	(5		)	(1		)	—
Power:
Forwards	(2		)	—			(2		)	—
Futures	(3		)	(3		)	—			—
Refined Products — Futures	(1		)	(1		)	—			—
Total commodity derivatives	(164		)	(151		)	(13		)	—
Total liabilities	$	(280	)	$	(151	)	$	(109	)	$	(20	)

	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 three months ended March 31, 2014. There were no transfers between the fair value hierarchy levels during the three months ended March 31, 2014 or 2013.

Balance, December 31, 2013	$	(19	)
Net unrealized loss included in other income (expense)	(1		)
Balance, March 31, 2014	$	(20	)

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Inventories (Tables)

3 Months Ended

Mar. 31, 2014

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:

	March 31, 2014		December 31, 2013
Natural gas and NGLs	$	239	$	523
Crude oil	572		488
Refined products	466		597
Other	207		199
Total inventories	$	1,484	$	1,807

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Equity Table - Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Partners' Capital Notes [Abstract]
Available-for-sale securities	$ 2	$ 2
Foreign currency translation adjustment	(4)	(1)
Net loss on commodity related hedges	(4)	(4)
Actuarial gain related to pensions and other postretirement benefits	55	56
Equity investments, net	1	8
Subtotal	50	61
Amounts attributable to noncontrolling interest	(44)	(52)
Accumulated other comprehensive income	$ 6	$ 9

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Cash And Cash Equivalents Table - Schedule of Non-Cash Investing & Financing Activities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 192	$ 434
Net gains from subsidiary common unit transactions	603	10
NON-CASH FINANCING ACTIVITIES:
Partners' Capital Account, Acquisitions	4,015	0
Noncash or Part Noncash Acquisition, Debt Assumed	$ 1,887	$ 0

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Net Income per Limited Partner Unit (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2014			2013
Income from continuing operations	$	424		$	300
Less: Income from continuing operations attributable to noncontrolling interest	259			224
Income from continuing operations, net of noncontrolling interest	165			76
Less: Class D Unitholder’s interest in income from continuing operations	1			—
Income from continuing operations available to Limited Partners	$	164		$	76
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	557.7			559.9
Basic income from continuing operations per Limited Partner unit	$	0.30		$	0.14
Basic income from discontinued operations per Limited Partner unit	$	0.00		$	0.02
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	164		$	76
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1		)	—
Diluted income from continuing operations available to Limited Partners	$	163		$	76
Weighted average limited partner units	557.7			559.9
Dilutive effect of unconverted unit awards	0.7			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	558.4			559.9
Diluted income from continuing operations per Limited Partner unit	$	0.30		$	0.14
Diluted income from discontinued operations per Limited Partner unit	$	0.00		$	0.02

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Debt Obligations Debt Table (Tables)

3 Months Ended

Mar. 31, 2014

Debt Instrument [Line Items]

Schedule of Debt [Table Text Block]

DEBT OBLIGATIONS:

Our outstanding consolidated indebtedness was as follows:

	March 31, 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	450		450
ETE Senior Secured Term Loan due December 2, 2019	1,000		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	520		171
Subsidiary Indebtedness:
ETP Senior Notes	11,182		11,182
Regency Senior Notes	3,700		2,800
PVR Senior Notes	1,173		—
Transwestern Senior Unsecured Notes	870		870
Panhandle Senior Notes	1,085		1,085
Sunoco Senior Notes	965		965
Sunoco Logistics Senior Notes	1,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	—		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	606		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	950		200
Other Long-Term Debt	228		228
Unamortized discounts, premiums and fair value adjustments, net	367		301
Total	26,293		23,199
Less: Current maturities of long-term debt	1,388		637
Long-term debt and notes payable, less current maturities	$	24,905	$	22,562

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Acquisitions

3 Months Ended

Mar. 31, 2014

ACQUISITIONS AND DIVESTITURE [Abstract]

Acquisitions

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Pending Transactions

ETP’s Pending Acquisition of Susser Holdings

On April 27, 2014, ETP entered into a definitive merger agreement whereby ETP plans to acquire Susser Holdings in a unit and cash transaction for total consideration valued at approximately $1.8 billion (the “Susser Merger”). By acquiring Susser Holdings, ETP will own the general partner interest and the incentive distribution rights in Susser Petroleum, approximately 11 million Susser Petroleum common units (representing approximately 50.2% of Susser Petroleum’s outstanding units), and Susser Holdings’ existing retail operations, consisting of 630 convenience store locations. The Susser Merger is expected to close in the third quarter of 2014, subject to approval of the shareholders of Susser Holdings and customary regulatory approvals.

Regency’s Pending Acquisition of Eagle Rock’s Midstream Business

In December 2013, Regency entered into an agreement to purchase Eagle Rock’s midstream business for approximately $1.3 billion (the “Eagle Rock Acquisition”). This acquisition is expected to complement Regency’s core gathering and processing business and, when combined with the PVR Acquisition, is expected to further diversify Regency’s basin exposure in the Texas Panhandle, East Texas and South Texas. On April 29, 2014, Eagle Rock’s unitholders approved the Eagle Rock Acquisition. After receiving that approval, all significant closing conditions have been met with the exception of the Federal Trade Commission’s (“FTC”) antitrust approval. On April 30, 2014, Regency and Eagle Rock certified substantial compliance with the FTC in response to its Request for Additional Information and Documentary Material regarding the Eagle Rock Acquisition.  In order to facilitate the FTC’s review, Eagle Rock and Regency have agreed with the FTC to not close the proposed transaction before June 30, 2014, unless the FTC first closes its investigation.

Closed Transactions

Panhandle Merger

On January 10, 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, a wholly-owned subsidiary of Southern Union, were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle as the surviving entity. 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.

Trunkline LNG Transaction

On February 19, 2014, ETP completed the transfer to ETE of Trunkline 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 “Trunkline LNG Transaction”). This transaction waseffective as of January 1, 2014, at which time ETP deconsolidated Trunkline LNG, including goodwill of$184 millionand intangible assets of$50 millionrelated to Trunkline LNG.

In connection with ETE’s acquisition of Trunkline LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline 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 9.

Regency’s Acquisition of PVR

On March 21, 2014, Regency acquired all of the PVR outstanding units 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 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. From March 21, 2014 through March 31, 2014, revenues and net income attributable to PVR’s operations of $37 million and $2 million, respectively, are included in Regency’s results of operations.

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

	March 21, 2014
Current assets	$	150
Plant, property and equipment	2,687
Investment in unconsolidated affiliates	62
Goodwill and intangible assets	3,079
Total assets acquired	$	5,978
Current liabilities	166
Long-term debt	1,887
Asset retirement obligations	3
Net assets acquired	$	3,922

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. From February 3, 2014 through March 31, 2014, revenues and net income attributable to Hoover’s operations of $5 million and $2 million, respectively, included in Regency’s results of operations.

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

	February 3, 2014
Current assets	$	5
Property, plant and equipment	114
Goodwill and intangible assets	181
Total assets acquired	$	300
Current liabilities	5
Asset retirement obligations	2
Net assets acquired	$	293

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three months ended March 31, 2014 and 2013 are presented as if the PVR and Hoover 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.

	Three Months Ended March 31,
	2014		2013
Revenues	$	13,362	$	11,449
Net income attributable to partners	161		84
Basic net income per Limited Partner unit	$	0.29	$	0.15
Diluted net income per Limited Partner unit	$	0.29	$	0.15

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 three months ended March 31, 2014 included the results of operations for a marketing business that had been recently acquired by ETP and was sold effective April 1, 2014. 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 months ended March 31, 2013 included the results of Southern Union’s distribution operations.

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Equity (Tables)

3 Months Ended

Mar. 31, 2014

Schedule of Net IDR Subsidies [Table Text Block]

	Total Year
2014 (remainder)	$	80
2015	51
2016	72
2017	50
2018	45
2019	35

Change In ETE Common Units

The change in ETE Common Units during the three months ended March 31, 2014 was as follows:

	Number of Units
Outstanding at December 31, 2013	559.9
Repurchase of units under buyback program	(8.1	)
Outstanding at March 31, 2014	551.8

Accumulated Other Comprehensive Income

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

	March 31, 2014			December 31, 2013
Available-for-sale securities	$	2		$	2
Foreign currency translation adjustment	(4		)	(1		)
Net loss on commodity related hedges	(4		)	(4		)
Actuarial gain related to pensions and other postretirement benefits	55			56
Equity investments, net	1			8
Subtotal	50			61
Amounts attributable to noncontrolling interest	(44		)	(52		)
Total AOCI, net of tax	$	6		$	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

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	$	0.92000
March 31, 2014	May 5, 2014	May 15, 2014	0.93500

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	$	0.47500
March 31, 2014	May 8, 2014	May 15, 2014	0.48000

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	$	0.66250
March 31, 2014	May 9, 2014	May 15, 2014	0.69500

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Acquisitions Narrative (Details) (USD $)	3 Months Ended							1 Months Ended		3 Months Ended								1 Months Ended		1 Months Ended			1 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Jan. 09, 2014	Mar. 21, 2014 PVR Acquisition [Member]	Mar. 03, 2014 Hoover Midstream Acquisition [Member]	Apr. 27, 2014 Susser Merger [Member]	Mar. 31, 2014 Eagle Rock Midstream Acquisition [Member]	Mar. 21, 2014 Regency [Member] PVR Acquisition [Member]	Feb. 28, 2014 Regency [Member] Hoover Midstream Acquisition [Member]	Mar. 31, 2014 PVR [Member]	Mar. 31, 2014 ETP [Member]	Mar. 31, 2014 Holdco [Member]	Mar. 31, 2014 Hoover Energy [Member]	Jan. 09, 2014 Panhandle [Member] ETP [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]	Jan. 09, 2014 Class F Units [Member] Panhandle [Member] Regency [Member] SUGS Contribution [Member]	Apr. 30, 2014 Common Units [Member] Susser Petroleum [Member] Susser Merger [Member]	Apr. 27, 2014 Common Units [Member] Susser Petroleum [Member] Susser Merger [Member]	Mar. 21, 2014 Common Units [Member] Regency [Member] PVR 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 Trunkline LNG Transaction [Member]
Business Combination, Cost of Acquired Entity, Purchase Price				$ 3,922,000,000	$ 293,000,000	$ 1,800,000,000	$ 1,300,000,000
Debt Instrument, Interest Rate, Stated Percentage															7.60%	8.25%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares																		11,000,000		140,400,000	4,040,471
Common Units Representing An Aggregate Limited Partner Interest																			50.20%
Number of Stores						630
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest												60.00%
Business Combination, Consideration Transferred								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								36,000,000	184,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				3,000,000	2,000,000
Revenues	13,080,000,000	11,179,000,000								37,000,000			5,000,000
Net Income (Loss) Attributable to Parent	168,000,000	90,000,000								2,000,000			2,000,000
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)												18,700,000
Goodwill, Written off Related to Sale of Business Unit																							184,000,000
Indefinite-lived Intangible Assets, Written off Related to Sale of Business Unit																							50,000,000
Related Party Transaction, Amounts of Transaction																							$ 75,000,000

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Equity Table - Change In ETE Common Units (Details) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Partners' Capital Notes [Abstract]
Outstanding at December 31, 2013	559.9
Stock Repurchased During Period, Shares	(8.1)
Outstanding at March 31, 2014	551.8

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Reportable Segments Table - Segment Assets (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Assets	$ 57,769	$ 50,330
Investment In ETP [Member]
Assets	43,589	43,702
Investment In Regency [Member]
Assets	15,197	8,782
Investment in Trunkline LNG [Member]
Assets	1,221	1,338
Corporate and Other [Member]
Assets	757	720
Adjustments And Eliminations [Member]
Assets	$ (2,995)	$ (4,212)

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
ASSETS
Cash and cash equivalents	$ 1,010	$ 590
Accounts receivable, net	4,423	3,658
Accounts receivable from related companies	40	63
Inventories	1,484	1,807
Exchanges receivable	101	67
Price risk management assets	12	39
Current assets held for sale	167	0
Other current assets	279	312
Total current assets	7,516	6,536
PROPERTY, PLANT AND EQUIPMENT	37,679	33,917
ACCUMULATED DEPRECIATION	(3,564)	(3,235)
PROPERTY, PLANT AND EQUIPMENT, net	34,115	30,682
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,818	4,014
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	1	18
GOODWILL	6,216	5,894
INTANGIBLE ASSETS, net	5,132	2,264
OTHER NON-CURRENT ASSETS, net	971	922
Total assets	57,769	50,330
LIABILITIES AND EQUITY
Accounts payable	4,272	3,834
Accounts payable to related companies	10	14
Exchanges payable	284	284
Price risk management liabilities	70	53
Accrued and other current liabilities	1,958	1,678
Current maturities of long-term debt	1,388	637
Current liabilities held for sale	109	0
Total current liabilities	8,091	6,500
LONG-TERM DEBT, less current maturities	24,905	22,562
DEFERRED INCOME TAXES	3,700	3,865
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	59	73
OTHER NON-CURRENT LIABILITIES	1,024	1,019
COMMITMENTS AND CONTINGENCIES (Note 12)
PREFERRED UNITS OF SUBSIDIARY	32	32
EQUITY:
General Partner	(1)	(3)
Limited Partners:
Common Unitholders	1,271	1,066
Class D Units	10	6
Accumulated other comprehensive income	6	9
Total partners’ capital	1,286	1,078
Noncontrolling interest	18,672	15,201
Total equity	19,958	16,279
Total liabilities and equity	$ 57,769	$ 50,330

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Inventories Table - Inventory Balances (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Inventory, Net [Abstract]
Natural gas and NGLs	$ 239	$ 523
Crude oil	572	488
Refined products	466	597
Other	207	199
Total inventories	$ 1,484	$ 1,807

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Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 448	$ 322
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	373	312
Deferred income taxes	(109)	3
Amortization included in interest expense	(12)	(16)
Non-cash compensation expense	20	16
Gain on sale of AmeriGas common units	(70)	0
LIFO valuation adjustments	(14)	(38)
Equity in earnings of unconsolidated affiliates	(104)	(90)
Distributions from unconsolidated affiliates	67	100
Other non-cash	(16)	17
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation	246	(296)
Net cash provided by operating activities	829	330
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(214)	0
Cash proceeds from the sale of AmeriGas common units	381	0
Capital expenditures (excluding allowance for equity funds used during construction)	(942)	(761)
Contributions in aid of construction costs	7	8
Contributions to unconsolidated affiliates	(50)	(1)
Distributions from unconsolidated affiliates in excess of cumulative earnings	27	30
Proceeds from the sale of assets	11	21
Other	(21)	3
Net cash used in investing activities	(801)	(700)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	3,170	2,899
Repayments of long-term debt	(1,977)	(1,961)
Subsidiary equity offerings, net of issue costs	175	192
Distributions to partners	195	179
Debt issuance costs	(17)	(16)
Distributions to noncontrolling interest	(397)	(333)
Capital contributions received from noncontrolling interest	0	11
Units repurchased under buyback program	(366)	0
Other, net	(1)	(1)
Net cash provided by financing activities	392	612
INCREASE IN CASH AND CASH EQUIVALENTS	420	242
CASH AND CASH EQUIVALENTS, beginning of period	590	372
CASH AND CASH EQUIVALENTS, end of period	$ 1,010	$ 614

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Narrative (Details) (USD $)	3 Months Ended				3 Months Ended		1 Months Ended				3 Months Ended			1 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Jan. 09, 2014	Dec. 31, 2013	Mar. 31, 2014 Attorneys' Fees [Member]	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]	Mar. 31, 2014 Plaintiff [Member]	Mar. 31, 2014 PVR [Member]	Mar. 31, 2014 Sunoco [Member]	Sep. 30, 2013 Attorney General of Commonwealth [Member]
Proceeds from Legal Settlements							$ 100,000,000
Loss Contingency, Damages Awarded, Value	24,000,000				10,000,000			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	32,000,000	33,000,000
Operating Leases, Rent Expense, Contingent Rentals	3,000,000	4,000,000
Operating Leases, Income Statement, Sublease Revenue	8,000,000	5,000,000
Invoices in Dispute	17,000,000
Loss Contingency, Damages Sought											30	21
Loss Contingency Accrual, at Carrying Value	41,000,000			46,000,000
Legal Fees														19,000,000
Percentage Of Recovery														50.00%
Reimbursement expert and consultant cost, maximum														150,000
Site Contingency, Number Of Sites Needing Remediation													39
Payments for Environmental Liabilities	$ 8,000,000	$ 7,000,000

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Price Risk Management Assets And Liabilities (Tables)

3 Months Ended

Mar. 31, 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 March 31,
		2014			2013
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	7		$	(4	)
Commodity derivatives — Non-Trading	Cost of products sold	(6		)	(21		)
Commodity derivatives — Non-Trading	Deferred gas purchases	—			(5		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(2		)	6
Embedded derivatives	Other income	(1		)	(14		)
Total		$	(2	)	$	(38	)

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)	March 31, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	400	$	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	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 3.80% and receive a floating rate	275		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
	March 31, 2014		December 31, 2013		March 31, 2014			December 31, 2013
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	1	$	3	$	(12	)	$	(18	)
	1		3		(12		)	(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	128	$	227	$	(139	)	$	(209	)
Commodity derivatives	60		43		(64		)	(48		)
Interest rate derivatives	4		47		(96		)	(95		)
Embedded derivatives in Regency Preferred Units	—		—		(20		)	(19		)
	192		317		(319		)	(371		)
Total derivatives	$	193	$	320	$	(331	)	$	(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	March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
Derivatives in offsetting agreements:
OTC contracts	Price risk management asset (liability)	$	60		$	42		$	(56	)	$	(38	)
Broker cleared derivative contracts	Other current assets (liabilities)	188			264			(254		)	(318		)
		248			306			(310		)	(356		)
Offsetting agreements:
Counterparty netting	Price risk management asset (liability)	(52		)	(36		)	52			36
Payments on margin deposit	Other current assets (liabilities)	(10		)	(1		)	54			55
		(62		)	(37		)	106			91
Net derivatives with offsetting agreements		186			269			(204		)	(265		)
Derivatives without offsetting agreements		7			51			(127		)	(124		)
Total derivatives		$	193		$	320		$	(331	)	$	(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 March 31,
	2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(4	)	$	2
Total	$	(4	)	$	2

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 March 31,
		2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(4	)	$	1
Total		$	(4	)	$	1

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

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended March 31,
		2014			2013
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(6	)	$	5
Total		$	(6	)	$	5

ETP [Member]

Outstanding Commodity-Related Derivatives

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

	March 31, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	10,475,000		2014-2019	9,457,500		2014-2019
Basis Swaps IFERC/NYMEX (1)	(14,502,500	)	2014-2015	(487,500	)	2014-2017
Swing Swaps	—		—	1,937,500		2014-2016
Power (Megawatt):
Forwards	527,550		2014	351,050		2014
Futures	(1,161,949	)	2014	(772,476	)	2014
Options — Puts	(160,000	)	2014	(52,800	)	2014
Options — Calls	104,800		2014	103,200		2014
Crude (Bbls) — Futures	343,000		2014	103,000		2014
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	3,520,000		2014	570,000		2014
Swing Swaps IFERC	32,690,000		2014	(9,690,000	)	2014-2016
Fixed Swaps/Futures	(1,402,500	)	2014-2015	(8,195,000	)	2014-2015
Forward Physical Contracts	(5,483,135	)	2014-2015	5,668,559		2014-2015
Natural Gas Liquid (Bbls) — Forwards/Swaps	(904,000	)	2014	(1,133,600	)	2014
Refined Products (Bbls) — Futures	(123,000	)	2014	(280,000	)	2014
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	—		—	(7,352,500	)	2014
Fixed Swaps/Futures	(4,500,000	)	2014	(50,530,000	)	2014
Hedged Item — Inventory	4,500,000		2014	50,530,000		2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,375,000	)	2014	(1,825,000	)	2014
Fixed Swaps/Futures	(9,625,000	)	2014	(12,775,000	)	2014
Natural Gas Liquid (Bbls) — Forwards/Swaps	(765,000	)	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:

	March 31, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(23,425,000	)	2014-2015	(24,455,000	)	2014-2015
Propane (Gallons) — Forwards/Swaps	(40,782,000	)	2014-2015	(52,122,000	)	2014-2015
NGLs (Barrels) — Forwards/Swaps	(330,000	)	2014	(438,000	)	2014
WTI Crude Oil (Barrels) — Forwards/Swaps	(392,000	)	2014	(521,000	)	2014

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Price Risk Management Assets And Liabilities Table - Gross FV and Netting Offset (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 193	$ 320
Derivative Liability, Fair Value, Gross Liability	(331)	(389)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(62)	(37)
Derivative Liability, Fair Value, Amount Offset Against Collateral	106	91
Netting [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	248	306
Derivative Liability, Fair Value, Gross Liability	(310)	(356)
Derivative Asset, Fair Value, Gross Liability	(52)	(36)
Derivative Liability, Fair Value, Gross Asset	52	36
Derivative Asset, Fair Value, Net	186	269
Derivative Liability, Fair Value, Net	(204)	(265)
Netting [Member] | Bi-lateral contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	60	42
Derivative Liability, Fair Value, Gross Liability	(56)	(38)
Netting [Member] | Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	188	264
Derivative Liability, Fair Value, Gross Liability	(254)	(318)
Netting [Member] | Asset Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Payments on Margin Deposits	(10)	(1)
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value	7	51
Netting [Member] | Liability Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Payments on Margin Deposits	54	55
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	$ (127)	$ (124)

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Reportable Segments

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

As a result of the Trunkline 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 Trunkline LNG, including the operations of Trunkline 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, 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 Trunkline LNG prior to the Trunkline LNG Transaction, which was effective January 1, 2014. The Investment in Trunkline LNG segment reflected the results of operations of Trunkline LNG for all periods presented. Consequently, the results of operations of Trunkline LNG were reflected in two segments for the three months ended March 31, 2013. Therefore, the results of Trunkline LNG were included in eliminations for 2013.

The following tables present financial information by segment:

	Three Months Ended March 31,
	2014			2013
Segment Adjusted EBITDA:
Investment in ETP	$	1,206		$	956
Investment in Regency	205			120
Investment in Trunkline LNG	48			45
Corporate and Other	(26		)	(6		)
Adjustments and Eliminations	(58		)	(63		)
Total	1,375			1,052
Depreciation and amortization	(373		)	(312		)
Interest expense, net of interest capitalized	(315		)	(310		)
Gain on sale of AmeriGas common units	70			—
Gains (losses) on interest rate derivatives	(2		)	6
Non-cash unit-based compensation expense	(20		)	(16		)
Unrealized gains (losses) on commodity risk management activities	(33		)	1
LIFO valuation adjustments	14			38
Equity in earnings of unconsolidated affiliates	104			90
Adjusted EBITDA related to unconsolidated affiliates	(210		)	(204		)
Adjusted EBITDA related to discontinued operations	(27		)	(40		)
Other, net	(14		)	(7		)
Income from continuing operations before income tax expense	$	569		$	298

	March 31, 2014			December 31, 2013
Total assets:
Investment in ETP	$	43,589		$	43,702
Investment in Regency	15,197			8,782
Investment in Trunkline LNG	1,221			1,338
Corporate and Other	757			720
Adjustments and Eliminations	(2,995		)	(4,212		)
Total	$	57,769		$	50,330

	Three Months Ended March 31,
	2014			2013
Revenues:
Investment in ETP:
Revenues from external customers	$	12,212		$	10,837
Intersegment revenues	20			17
	12,232			10,854
Investment in Regency:
Revenues from external customers	806			535
Intersegment revenues	57			5
	863			540
Investment in Trunkline LNG:
Revenues from external customers	54			53
Adjustments and Eliminations	(69		)	(268		)
Total revenues	$	13,080		$	11,179

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 Trunkline LNG.

Investment in ETP

	Three Months Ended March 31,
	2014		2013
Intrastate Transportation and Storage	$	847	$	645
Interstate Transportation and Storage	295		323
Midstream	302		331
NGL Transportation and Services	801		346
Investment in Sunoco Logistics	4,452		3,457
Retail Marketing	5,008		5,217
All Other	527		535
Total revenues	12,232		10,854
Less: Intersegment revenues	20		17
Revenues from external customers	$	12,212	$	10,837

Investment in Regency

	Three Months Ended March 31,
	2014		2013
Gathering and Processing	$	793	$	486
Contract Services	63		49
Natural Resources	2		—
Corporate and Other	5		5
Total revenues	863		540
Less: Intersegment revenues	57		5
Revenues from external customers	$	806	$	535

Investment in Trunkline LNG

Trunkline LNG’s revenue of $54 million and $53 million for the three months ended March 31, 2014 and 2013, respectively, were related to LNG terminalling.

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Other Information (Tables)

3 Months Ended

Mar. 31, 2014

Other Information [Abstract]

Other Current Assets

Other current assets consisted of the following:

	March 31, 2014		December 31, 2013
Deposits paid to vendors	$	33	$	49
Prepaid expenses and other	246		263
Total other current assets	$	279	$	312

Accrued And Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	March 31, 2014		December 31, 2013
Interest payable	$	411	$	357
Customer advances and deposits	81		142
Accrued capital expenditures	224		260
Accrued wages and benefits	118		173
Taxes payable other than income taxes	237		211
Income taxes payable	240		4
Deferred income taxes	164		119
Deferred revenue	66		—
Other	417		412
Total accrued and other current liabilities	$	1,958	$	1,678

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Operations And Organization Accounting policy (Policies)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (“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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Other Information Table - Other Current Assets (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Other Information [Abstract]
Deposits paid to vendors	$ 33	$ 49
Prepaid expenses and other	246	263
Total other current assets	$ 279	$ 312

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Operations And Organization

3 Months Ended

Mar. 31, 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.

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, Trunkline LNG, which 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 Trunkline 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 17 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 our 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 our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star and also owns MACS, a convenience store operator.

• 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. As discussed in Note 2, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. 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.

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

• Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas and the transportation, fractionation and storage of NGLs. 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 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.

• Trunkline 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. Trunkline LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

Our reportable segments 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 Trunkline LNG, including the operations of Trunkline 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 March 31, 2014 and for the three months ended March 31, 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 March 31, 2014, and the Partnership’s results of operations and cash flows for the three months ended March 31, 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 $530 million and $514 million for the three months ended March 31, 2014 and 2013, respectively.

New Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (“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
	Mar. 31, 2014	Mar. 31, 2013
REVENUES:
Natural gas sales	$ 1,430	$ 973
NGL sales	1,254	713
Crude sales	4,093	3,201
Gathering, transportation and other fees	872	740
Refined product sales	4,478	4,662
Other	953	890
Total revenues	13,080	11,179
COSTS AND EXPENSES:
Cost of products sold	11,442	9,807
Operating expenses	407	372
Depreciation and amortization	373	312
Selling, general and administrative	148	157
Total costs and expenses	12,370	10,648
OPERATING INCOME	710	531
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(315)	(310)
Equity in earnings of unconsolidated affiliates	104	90
Gains (losses) on interest rate derivatives	(2)	6
Gain on sale of AmeriGas common units	70	0
Other, net	2	(19)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	569	298
Income tax expense (benefit) from continuing operations	145	(2)
INCOME FROM CONTINUING OPERATIONS	424	300
Income from discontinued operations	24	22
NET INCOME	448	322
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	280	232
NET INCOME ATTRIBUTABLE TO PARTNERS	168	90
GENERAL PARTNER’S INTEREST IN NET INCOME	0	0
Class D Unitholder's interest in Net Income	1	0
LIMITED PARTNERS’ INTEREST IN NET INCOME	$ 167	$ 90
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$ 0.30	$ 0.14
Diluted	$ 0.30	$ 0.14
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$ 0.30	$ 0.16
Diluted	$ 0.30	$ 0.16

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Retirement Benefits

3 Months Ended

Mar. 31, 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 March 31,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—		$	—		$	2		$	—
Interest cost	8			1			9			2
Expected return on plan assets	(11		)	(2		)	(15		)	(3		)
Actuarial (gain) loss amortization	(1		)	—			1			—
Settlement credits	(1		)	—			(2		)	—
	(5		)	(1		)	(5		)	(1		)
Regulatory adjustment	—			—			2			—
Net periodic benefit cost	$	(5	)	$	(1	)	$	(3	)	$	(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 MEG and NEG in 2013.

XML

DEI Document	3 Months Ended
	Mar. 31, 2014	May 02, 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	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		543,712,024

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

3 Months Ended

Mar. 31, 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

On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”).

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.

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.  Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled $32 million and $33 million for the three months endedMarch 31, 2014 and 2013, respectively, which include contingent rentals totaling $3 million and $4 million in the three months ended March 31, 2014 and 2013, respectively.  During the three months ended March 31, 2014 and 2013, $8 million and $5 million, respectively, of rental expense was recovered through related sublease rental income.

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 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, injunctive relief, punitive damages and attorneys’ fees.

As of March 31, 2014, Sunoco is a defendant in seven cases, one of which was initiated by the State of New Jersey 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 and Puerto Rico cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting 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; however, it is reasonably possible that a loss may be realized. 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 to be 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. vs. 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. In addition, the jury may order interest and attorneys’ fees against Regency Marcellus of approximately $10 million. The jury found against Regency Marcellus on its counterclaims. Regency Marcellus has filed appropriate post-trial pleadings and is considering its appeal options.

Litigation Related to the Eagle Rock Acquisition

Two putative class action lawsuits challenging Regency’s acquisition of the Eagle Rock midstream assets are currently pending in federal district court in Houston, Texas. Both cases name Eagle Rock and its current directors, as well as Regency and a subsidiary (collectively, the “Regency Defendants”), 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 enjoin 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. The Regency Defendants 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 March 31, 2014 and December 31, 2013, accruals of approximately $41 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.

No amounts have been recorded in our March 31, 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 identified as a potentially responsible party (“PRP”).  As ofMarch 31, 2014, Sunoco had been named as a PRP at39identified or potentially identifiable as “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.  Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

	March 31, 2014		December 31, 2013
Current	$	72	$	47
Non-current	339		356
Total environmental liabilities	$	411	$	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 March 31, 2014 and 2013, the Partnership recorded $8 million and $7 million, respectively, of expenditures related to environmental cleanup programs.

On June 29, 2011, the EPA finalized a rule under the CAA 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 DOT 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 June 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.

XML

Consolidated Statements Of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 448	$ 322
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	4	(1)
Change in value of derivative instruments accounted for as cash flow hedges	(4)	2
Change in value of available-for-sale securities	0	1
Actuarial loss relating to pension and other postretirement benefits	(1)	(1)
Foreign currency translation adjustment	(3)	(1)
Change in other comprehensive income from equity investments	(7)	7
Other comprehensive income (loss), net of tax	(11)	7
Comprehensive income	437	329
Less: Comprehensive income attributable to noncontrolling interest	272	238
Comprehensive income attributable to partners	$ 165	$ 91

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 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.

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 March 31, 2014 and December 31, 2013 was $27.64 billion and $23.97 billion, respectively. As of March 31, 2014 and December 31, 2013, the aggregate carrying amount of our consolidated debt obligations was $26.29 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 March 31, 2014 and December 31, 2013 based on inputs used to derive their fair values:

	Fair Value Measurements at March 31, 2014
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	4		$	—		$	4		$	—
Commodity derivatives:
Condensate — Forward Swaps	—			—			—			—
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	1			1			—			—
Fixed Swaps/Futures	118			118			—			—
NGLs — Forwards/Swaps	6			3			3			—
Power:
Forwards	5			—			5			—
Futures	1			1			—
Refined Products — Futures	1			1			—			—
Crude — Futures	1			1			—			—
Total commodity derivatives	138			130			8			—
Total assets	$	142		$	130		$	12		$	—
Liabilities:
Interest rate derivatives	$	(96	)	$	—		$	(96	)	$	—
Embedded derivatives in the Regency Preferred Units	(20		)	—			—			(20		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(3		)	(3		)	—			—
Swing Swaps IFERC	(4		)	(4		)	—			—
Fixed Swaps/Futures	(145		)	(135		)	(10		)	—
NGLs — Forwards/Swaps	(6		)	(5		)	(1		)	—
Power:
Forwards	(2		)	—			(2		)	—
Futures	(3		)	(3		)	—			—
Refined Products — Futures	(1		)	(1		)	—			—
Total commodity derivatives	(164		)	(151		)	(13		)	—
Total liabilities	$	(280	)	$	(151	)	$	(109	)	$	(20	)

	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 three months ended March 31, 2014. There were no transfers between the fair value hierarchy levels during the three months ended March 31, 2014 or 2013.

Balance, December 31, 2013	$	(19	)
Net unrealized loss included in other income (expense)	(1		)
Balance, March 31, 2014	$	(20	)

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Inventories (Notes)

3 Months Ended

Mar. 31, 2014

Inventory, Net [Abstract]

Inventories

INVENTORIES:

Inventories consisted of the following:

	March 31, 2014		December 31, 2013
Natural gas and NGLs	$	239	$	523
Crude oil	572		488
Refined products	466		597
Other	207		199
Total inventories	$	1,484	$	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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Supplemental Financial Statement Information

3 Months Ended

Mar. 31, 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)

	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16		$	8
Accounts receivable from related companies	6			5
Other current assets	1			—
Total current assets	23			13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,448			3,841
INTANGIBLE ASSETS, net	13			14
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	41			41
Total assets	$	4,534		$	3,918
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related companies	$	42		$	11
Interest payable	53			24
Accrued and other current liabilities	2			3
Total current liabilities	97			38
LONG-TERM DEBT, less current maturities	3,150			2,801
OTHER NON-CURRENT LIABILITIES	1			1
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	1,271			1,066
Class D Units	10			6
Accumulated other comprehensive income	6			9
Total partners’ capital	1,286			1,078
Total liabilities and partners’ capital	$	4,534		$	3,918

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2014			2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(31	)	$	(6	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(40		)	(64		)
Equity in earnings of unconsolidated affiliates	239			168
Other, net	—			(8		)
INCOME BEFORE INCOME TAXES	168			90
Income tax expense	—			—
NET INCOME	168			90
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	167		$	90

STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2014			2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	229		$	182
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(7		)	—
Net cash used in investing activities	(7		)	—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	405			95
Principal payments on debt	(56		)	(65		)
Distributions to partners	(195		)	(179		)
Units repurchased under buyback program	(366		)	—
Debt issuance costs	(2		)	—
Net cash used in financing activities	(214		)	(149		)
INCREASE IN CASH AND CASH EQUIVALENTS	8			33
CASH AND CASH EQUIVALENTS, beginning of period	8			9
CASH AND CASH EQUIVALENTS, end of period	$	16		$	42

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Price Risk Management Assets And Liabilities

3 Months Ended

Mar. 31, 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’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 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.

Derivatives are utilized in ETP’s other operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist.

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

	March 31, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	10,475,000		2014-2019	9,457,500		2014-2019
Basis Swaps IFERC/NYMEX (1)	(14,502,500	)	2014-2015	(487,500	)	2014-2017
Swing Swaps	—		—	1,937,500		2014-2016
Power (Megawatt):
Forwards	527,550		2014	351,050		2014
Futures	(1,161,949	)	2014	(772,476	)	2014
Options — Puts	(160,000	)	2014	(52,800	)	2014
Options — Calls	104,800		2014	103,200		2014
Crude (Bbls) — Futures	343,000		2014	103,000		2014
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	3,520,000		2014	570,000		2014
Swing Swaps IFERC	32,690,000		2014	(9,690,000	)	2014-2016
Fixed Swaps/Futures	(1,402,500	)	2014-2015	(8,195,000	)	2014-2015
Forward Physical Contracts	(5,483,135	)	2014-2015	5,668,559		2014-2015
Natural Gas Liquid (Bbls) — Forwards/Swaps	(904,000	)	2014	(1,133,600	)	2014
Refined Products (Bbls) — Futures	(123,000	)	2014	(280,000	)	2014
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	—		—	(7,352,500	)	2014
Fixed Swaps/Futures	(4,500,000	)	2014	(50,530,000	)	2014
Hedged Item — Inventory	4,500,000		2014	50,530,000		2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,375,000	)	2014	(1,825,000	)	2014
Fixed Swaps/Futures	(9,625,000	)	2014	(12,775,000	)	2014
Natural Gas Liquid (Bbls) — Forwards/Swaps	(765,000	)	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 losses of $4 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. Speculative positions are prohibited under Regency’s policy.

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

	March 31, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(23,425,000	)	2014-2015	(24,455,000	)	2014-2015
Propane (Gallons) — Forwards/Swaps	(40,782,000	)	2014-2015	(52,122,000	)	2014-2015
NGLs (Barrels) — Forwards/Swaps	(330,000	)	2014	(438,000	)	2014
WTI Crude Oil (Barrels) — Forwards/Swaps	(392,000	)	2014	(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)	March 31, 2014		December 31, 2013
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	$	400	$	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	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 3.80% and receive a floating rate	275		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 March 31, 2014 would be $3 million, which would be reduced by $2 million, due to the netting feature.

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

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2014		December 31, 2013		March 31, 2014			December 31, 2013
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	1	$	3	$	(12	)	$	(18	)
	1		3		(12		)	(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	128	$	227	$	(139	)	$	(209	)
Commodity derivatives	60		43		(64		)	(48		)
Interest rate derivatives	4		47		(96		)	(95		)
Embedded derivatives in Regency Preferred Units	—		—		(20		)	(19		)
	192		317		(319		)	(371		)
Total derivatives	$	193	$	320	$	(331	)	$	(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	March 31, 2014			December 31, 2013			March 31, 2014			December 31, 2013
Derivatives in offsetting agreements:
OTC contracts	Price risk management asset (liability)	$	60		$	42		$	(56	)	$	(38	)
Broker cleared derivative contracts	Other current assets (liabilities)	188			264			(254		)	(318		)
		248			306			(310		)	(356		)
Offsetting agreements:
Counterparty netting	Price risk management asset (liability)	(52		)	(36		)	52			36
Payments on margin deposit	Other current assets (liabilities)	(10		)	(1		)	54			55
		(62		)	(37		)	106			91
Net derivatives with offsetting agreements		186			269			(204		)	(265		)
Derivatives without offsetting agreements		7			51			(127		)	(124		)
Total derivatives		$	193		$	320		$	(331	)	$	(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 March 31,
	2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(4	)	$	2
Total	$	(4	)	$	2

	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 March 31,
		2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(4	)	$	1
Total		$	(4	)	$	1

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended March 31,
		2014			2013
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(6	)	$	5
Total		$	(6	)	$	5

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2014			2013
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	7		$	(4	)
Commodity derivatives — Non-Trading	Cost of products sold	(6		)	(21		)
Commodity derivatives — Non-Trading	Deferred gas purchases	—			(5		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(2		)	6
Embedded derivatives	Other income	(1		)	(14		)
Total		$	(2	)	$	(38	)

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Equity

3 Months Ended

Mar. 31, 2014

Partners' Capital Notes [Abstract]

Equity

EQUITY:

ETE Common Unit Activity

The change in ETE Common Units during the three months ended March 31, 2014 was as follows:

	Number of Units
Outstanding at December 31, 2013	559.9
Repurchase of units under buyback program	(8.1	)
Outstanding at March 31, 2014	551.8

From January through April, ETE repurchased approximately $750 million of ETE common units under 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 thethreemonths endedMarch 31, 2014, we recognized increases in partners’ capital of$603 million.

Sales of Common Units by ETP

ETP has entered into an Equity Distribution Agreement pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to an agreed-upon threshold. During thethree months ended March 31,2014, ETP received proceeds of$106 million, net of commissions of$1 million, from the issuance of units pursuant to the Equity Distribution Agreement, which proceeds were used for general partnership purposes. ETP also received $38 million, net of commissions, in April 2014 from the settlement of transactions initiated in March 2014 under this agreement. No amounts remain available to be issued under this agreement.

During the three months ended March 31,2014, distributions of$36 millionwere reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of0.7 millionETP Common Units. As ofMarch 31, 2014, a total of1.4 millionETP Common Units remain available to be issued under the existing registration statement for ETP’s Distribution Reinvestment Plan.

As discussed in Note 2, ETP redeemed and cancelled 18.7 million of its Common Units in connection with the Trunkline LNG Transaction.

Sales of Common Units by Regency

From time to time, Regency has sold Regency Common Units through an Equity Distribution Agreement, such sales of Regency Common Units are made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by Regency and the sales agent which is the counterparty to the equity distribution agreement. For the three months ended March 31,2014, Regency received net proceeds of $34 million from units issued pursuant to its Equity Distribution Agreement, which proceeds were used for general partnership purposes. As of March 31, 2014, no amounts remain available to be issued under its agreement.

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

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

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	$	0.92000
March 31, 2014	May 5, 2014	May 15, 2014	0.93500

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 three months endedMarch 31, 2014, the net impact of these adjustments will result in a reduction of $26 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 current and future quarters:

	Total Year
2014 (remainder)	$	80
2015	51
2016	72
2017	50
2018	45
2019	35

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	$	0.47500
March 31, 2014	May 8, 2014	May 15, 2014	0.48000

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	$	0.66250
March 31, 2014	May 9, 2014	May 15, 2014	0.69500

On May 5, 2014, Sunoco Logistics’ Board of Directors declared a two-for-one split of Sunoco Logistics common units. The unit split will result 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 will be effective June 12, 2014. All Sunoco Logistics unit and per unit information is presented on a pre-split basis.

Accumulated Other Comprehensive Income

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

	March 31, 2014			December 31, 2013
Available-for-sale securities	$	2		$	2
Foreign currency translation adjustment	(4		)	(1		)
Net loss on commodity related hedges	(4		)	(4		)
Actuarial gain related to pensions and other postretirement benefits	55			56
Equity investments, net	1			8
Subtotal	50			61
Amounts attributable to noncontrolling interest	(44		)	(52		)
Total AOCI, net of tax	$	6		$	9

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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Table - Accrued Environmental Liabilities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Environmental Exit Cost [Line Items]
Current	$ 72	$ 47
Non-current	339	356
Total environmental liabilities	$ 411	$ 403

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Net Income per Limited Partner Unit

3 Months Ended

Mar. 31, 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 March 31,
	2014			2013
Income from continuing operations	$	424		$	300
Less: Income from continuing operations attributable to noncontrolling interest	259			224
Income from continuing operations, net of noncontrolling interest	165			76
Less: Class D Unitholder’s interest in income from continuing operations	1			—
Income from continuing operations available to Limited Partners	$	164		$	76
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	557.7			559.9
Basic income from continuing operations per Limited Partner unit	$	0.30		$	0.14
Basic income from discontinued operations per Limited Partner unit	$	0.00		$	0.02
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	164		$	76
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1		)	—
Diluted income from continuing operations available to Limited Partners	$	163		$	76
Weighted average limited partner units	557.7			559.9
Dilutive effect of unconverted unit awards	0.7			—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	558.4			559.9
Diluted income from continuing operations per Limited Partner unit	$	0.30		$	0.14
Diluted income from discontinued operations per Limited Partner unit	$	0.00		$	0.02

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Debt Obligations

3 Months Ended

Mar. 31, 2014

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

Our outstanding consolidated indebtedness was as follows:

	March 31, 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	450		450
ETE Senior Secured Term Loan due December 2, 2019	1,000		1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018	520		171
Subsidiary Indebtedness:
ETP Senior Notes	11,182		11,182
Regency Senior Notes	3,700		2,800
PVR Senior Notes	1,173		—
Transwestern Senior Unsecured Notes	870		870
Panhandle Senior Notes	1,085		1,085
Sunoco Senior Notes	965		965
Sunoco Logistics Senior Notes	1,975		2,150
Revolving Credit Facilities:
ETP $2.5 billion Revolving Credit Facility due October 27, 2017	—		65
Regency $1.5 billion Revolving Credit Facility due May 21, 2018	606		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	950		200
Other Long-Term Debt	228		228
Unamortized discounts, premiums and fair value adjustments, net	367		301
Total	26,293		23,199
Less: Current maturities of long-term debt	1,388		637
Long-term debt and notes payable, less current maturities	$	24,905	$	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

On April 16, 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 March 31, 2014, there were $520 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $280 million. The weighted average interest rate on the total amount outstanding as of March 31, 2014 was 2.16%.

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 $450 million 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 $1.17 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 April 2014, Regency commenced a private offer to exchange any and all outstanding 8.375% Eagle Rock Senior Notes due 2019, of which $550 million in aggregate principal amount is outstanding, for 8.375% Senior Notes due 2019 to be issued by Regency with substantially the same economic terms, and is contingent upon the closing of the Eagle Rock Acquisition. On April 28, 2014, Regency extended the expiration date on this exchange offer to May 28, 2014, unless further extended or terminated.

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 March 31, 2014, the ETP Credit Facility had no 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.

As of March 31, 2014, the Regency Credit Facility had a balance outstanding of $606 million in revolving credit loans and approximately $21 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2014, which was reduced by any letters of credit, was approximately $873 million, and the weighted average interest rate on the total amount outstanding as of March 31, 2014 was 2.41%.

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 extended to $2.25 billion under certain conditions. As of March 31, 2014, the Sunoco Logistics Credit Facility had $950 million outstanding.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2014.

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Income Taxes (Notes)

3 Months Ended

Mar. 31, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES:

The increase in the effective tax rate for the three months ended March 31, 2014 was primarily due to the Trunkline LNG Transaction (see Note 2). The Trunkline LNG Transaction, which was treated as a sale for tax purposes, resulted in $85 million of incremental income tax expense.

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Price Risk Management Assets And Liabilities Table - Fair Value of Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Total derivatives assets	$ 193	$ 320
Total derivatives liabilities	331	389
Designated as Hedging Instrument [Member]
Total derivatives assets	1	3
Total derivatives liabilities	12	18
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	1	3
Total derivatives liabilities	12	18
Not Designated as Hedging Instrument [Member]
Total derivatives assets	192	317
Total derivatives liabilities	319	371
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	128	227
Total derivatives liabilities	139	209
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	60	43
Total derivatives liabilities	64	48
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	4	47
Total derivatives liabilities	96	95
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ 20	$ 19

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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
	Mar. 31, 2014	Mar. 31, 2013
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ (4)	$ 2
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ (4)	$ 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	3 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
July 2014 [Member] | ETP [Member]
Notional Amount	$ 400	[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]
June 2021 [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]
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%
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%
November 2021 [Member] | Panhandle [Member]
Notional Amount	275		275
Type	Pay a fixed rate of 3.80% and receive a floating rate
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]

[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 (Tables)

3 Months Ended

Mar. 31, 2014

Environmental Exit Cost [Line Items]

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.  Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.

	March 31, 2014		December 31, 2013
Current	$	72	$	47
Non-current	339		356
Total environmental liabilities	$	411	$	403

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Debt Obligations Debt Table (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Other Long-term Debt	$ 228	$ 228
Debt Instrument, Unamortized Discount (Premium), Net	367	301
Long-term Debt	26,293	23,199
Current maturities of long-term debt	1,388	637
LONG-TERM DEBT, less current maturities	24,905	22,562
Parent Company [Member]
Debt Instrument [Line Items]
LONG-TERM DEBT, less current maturities	3,150	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	450	450
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2019 [Member]
Debt Instrument [Line Items]
Secured Debt	1,000	1,000
Parent Company [Member] | ETE Senior Secured Term Loan due December 2, 2018 [Member]
Debt Instrument [Line Items]
Secured Debt		171
Line of Credit Facility, Amount Outstanding	520
ETP [Member]
Debt Instrument [Line Items]
Senior Notes	11,182	11,182
ETP [Member] | ETP Revolving Credit Facility, due October 2017 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	0	65
Regency [Member]
Debt Instrument [Line Items]
Senior Notes	3,700	2,800
Regency [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	606	510
PVR [Member]
Debt Instrument [Line Items]
Senior Notes	1,173	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	1,975	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	$ 950	$ 200

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Other Information

3 Months Ended

Mar. 31, 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:

	March 31, 2014		December 31, 2013
Deposits paid to vendors	$	33	$	49
Prepaid expenses and other	246		263
Total other current assets	$	279	$	312

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	March 31, 2014		December 31, 2013
Interest payable	$	411	$	357
Customer advances and deposits	81		142
Accrued capital expenditures	224		260
Accrued wages and benefits	118		173
Taxes payable other than income taxes	237		211
Income taxes payable	240		4
Deferred income taxes	164		119
Deferred revenue	66		—
Other	417		412
Total accrued and other current liabilities	$	1,958	$	1,678

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Investments in Affiliates (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2014		2013
Revenue	$	1,819	$	1,511
Operating income	464		437
Net income	344		318

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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
	Mar. 31, 2014	Mar. 31, 2013
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Income from continuing operations	$ 424	$ 300
Less: Income from continuing operations attributable to noncontrolling interest	259	224
Income from continuing operations, net of noncontrolling interest	165	76
Less: Class D Unitholder’s interest in income from continuing operations	1	0
Income from continuing operations available to Limited Partners	164	76
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average Limited Partner units	557.7	559.9
Basic income from continuing operations per Limited Partner unit	$ 0.30	$ 0.14
Basic income from discontinued operations per Limited Partner unit	$ 0.00	$ 0.02
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
Diluted income from continuing operations available to Limited Partners	$ 163	$ 76
Dilutive effect of unconverted unit awards	0.7	0
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	558.4	559.9
Diluted income from continuing operations per Limited Partner unit	$ 0.30	$ 0.14
Diluted income from discontinued operations per Limited Partner unit	$ 0.00	$ 0.02

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Acquisitions Regency PPA (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 21, 2014 PVR Acquisition [Member]	Mar. 03, 2014 Hoover Midstream Acquisition [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue	$ 13,362	$ 11,449
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets			150	5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			2,687	114
Business Acquisition, Purchase Price Allocation, Investments in Affilaites			62
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net			3,079	181
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets			5,978	300
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities			166	5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt			1,887
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other			3	2
Business Combination, Cost of Acquired Entity, Purchase Price			3,922	293
Business Acquisition, Pro Forma Net Income (Loss)	$ 161	$ 84
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 0.29	$ 0.15
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 0.29	$ 0.15

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Consolidated Statement Of Equity (USD $) In Millions	Total	General Partner	Common Unitholders	Class D Units [Member]	Accumulated Other Comprehensive Income	Non- controlling Interest
Balance, December 31, 2013 at Dec. 31, 2013	$ 16,279	$ (3)	$ 1,066	$ 6	$ 9	$ 15,201
Distributions to partners	(195)	0	(194)	(1)	0	0
Distributions to noncontrolling interest	(397)	0	0	0	0	(397)
Subsidiary units issued for cash	175	0	17	0	0	158
Subsidiary units issued in certain acquisitions	4,015	0	104	0	0	3,911
Subsidiary units redeemed in Trunkline LNG Transaction	0	2	480	0	0	(482)
Non-cash compensation expense, net of units tendered by employees for tax withholdings	17	0	0	4	0	13
Other, net	(7)	0	(3)	0	0	(4)
Units repurchased under buyback program	(366)	0	(366)	0	0	0
Other comprehensive loss, net of tax	(11)	0	0	0	(3)	(8)
Net income	448	0	167	1	0	280
Balance, March 31, 2014 at Mar. 31, 2014	$ 19,958	$ (1)	$ 1,271	$ 10	$ 6	$ 18,672

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Cash And Cash Equivalents

3 Months Ended

Mar. 31, 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:

	Three Months Ended March 31,
	2014		2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	192	$	434
Net gains from subsidiary common unit transactions	$	603	$	10
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR and Hoover acquisitions	$	4,015	$	—
Long-term debt assumed in PVR acquisition	$	1,887	$	—

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Retirement Benefits Table - Components of Pension Expense (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 0	$ 2
Interest cost	8	9
Expected return on plan assets	(11)	(15)
Net periodic benefit cost subtotal	(5)	(5)
Regulatory adjustment	0	2
Net periodic benefit cost	(5)	(3)
Defined Benefit Plan, Amortization of Gains (Losses)	1	(1)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	1	2
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0
Interest cost	1	2
Expected return on plan assets	(2)	(3)
Net periodic benefit cost subtotal	(1)	(1)
Regulatory adjustment	0	0
Net periodic benefit cost	(1)	(1)
Defined Benefit Plan, Amortization of Gains (Losses)	0	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	$ 0	$ 0

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Other Information Table - Accrued and Other Current Liabilities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Other Information [Abstract]
Interest payable	$ 411	$ 357
Customer advances and deposits	81	142
Accrued Capital Expenditures	224	260
Accrued wages and benefits	118	173
Taxes payable other than income taxes	237	211
Income taxes payable	240	4
Deferred Tax Liabilities, Net, Current	164	119
Deferred Revenue, Current	66	0
Other Accrued Liabilities, Current	417	412
Total accrued and other current liabilities	$ 1,958	$ 1,678

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Cash And Cash Equivalents (Tables)

3 Months Ended

Mar. 31, 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:

	Three Months Ended March 31,
	2014		2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	192	$	434
Net gains from subsidiary common unit transactions	$	603	$	10
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR and Hoover acquisitions	$	4,015	$	—
Long-term debt assumed in PVR acquisition	$	1,887	$	—

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Reportable Segments Table - Revenues from External Customers by Segment (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 13,080	$ 11,179
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	12,232	10,854
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	863	540
Natural Resources [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	2	0
Gathering And Processing [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	793	486
Corporate and Other [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	5	5
Contract Services [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	63	49
Intersegment [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	20	17
Intersegment [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	57	5
Other Segments [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	527	535
NGL Transportation And Services [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	801	346
Midstream [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	302	331
Interstate Transportation and Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	295	323
Intrastate Transportation And Storage [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	847	645
Investment in Sunoco Logistics [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	4,452	3,457
Retail Marketing [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	5,008	5,217
External Customers [Member] | Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	12,212	10,837
External Customers [Member] | Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	$ 806	$ 535

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Supplemental Financial Statement Information (Tables)

3 Months Ended

Mar. 31, 2014

Schedule Of Balance Sheets

BALANCE SHEETS

(unaudited)

	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16		$	8
Accounts receivable from related companies	6			5
Other current assets	1			—
Total current assets	23			13
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,448			3,841
INTANGIBLE ASSETS, net	13			14
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	41			41
Total assets	$	4,534		$	3,918
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related companies	$	42		$	11
Interest payable	53			24
Accrued and other current liabilities	2			3
Total current liabilities	97			38
LONG-TERM DEBT, less current maturities	3,150			2,801
OTHER NON-CURRENT LIABILITIES	1			1
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	(3		)
Limited Partners:
Common Unitholders	1,271			1,066
Class D Units	10			6
Accumulated other comprehensive income	6			9
Total partners’ capital	1,286			1,078
Total liabilities and partners’ capital	$	4,534		$	3,918

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2014			2013
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(31	)	$	(6	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(40		)	(64		)
Equity in earnings of unconsolidated affiliates	239			168
Other, net	—			(8		)
INCOME BEFORE INCOME TAXES	168			90
Income tax expense	—			—
NET INCOME	168			90
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—
CLASS D UNITHOLDER’S INTEREST IN NET INCOME	1			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	167		$	90

Parent Company [Member]

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2014			2013
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	229		$	182
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate	(7		)	—
Net cash used in investing activities	(7		)	—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	405			95
Principal payments on debt	(56		)	(65		)
Distributions to partners	(195		)	(179		)
Units repurchased under buyback program	(366		)	—
Debt issuance costs	(2		)	—
Net cash used in financing activities	(214		)	(149		)
INCREASE IN CASH AND CASH EQUIVALENTS	8			33
CASH AND CASH EQUIVALENTS, beginning of period	8			9
CASH AND CASH EQUIVALENTS, end of period	$	16		$	42

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Related Party Transactions

3 Months Ended

Mar. 31, 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.