10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

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 August 2, 2013, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P. 280,711,650 Common Units

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 – June 30, 2013 and December 31, 2012	1
Consolidated Statements of Operations – Three and Six Months Ended June 30, 2013 and 2012	3
Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2013 and 2012	4
Consolidated Statement of Equity – Six Months Ended June 30, 2013	5
Consolidated Statements of Cash Flows – Six Months Ended June 30, 2013 and 2012	6
Notes to Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	39
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	55
ITEM 4. CONTROLS AND PROCEDURES	58
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	59
ITEM 1A. RISK FACTORS	59
ITEM 6. EXHIBITS	60
SIGNATURE	61

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, 2012 filed with the Securities and Exchange Commission on March 1, 2013.

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
Canyon	ETC Canyon Pipeline, LLC
Citrus	Citrus Corp., which owns 100% of FGT
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 revolving credit facility
ETP GP	Energy Transfer Partners GP, L.P., the general partner of ETP
ETP LLC	Energy Transfer Partners, L.L.C., the general partner of ETP GP
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
Holdco Transaction	October 5, 2012 transaction including contributions from ETP and ETE to Holdco
IDRs	incentive distribution rights
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas

ii

Lone Star	Lone Star NGL LLC
MEP	Midcontinent Express Pipeline LLC
MMBtu	million British thermal units
MTBE	methyl tertiary butyl ether
NGL	natural gas liquid, such as propane, butane and natural gasoline
NYMEX	New York Mercantile Exchange
OTC	over-the-counter
OSHA	Federal Occupational Safety and Health Act
Panhandle	Panhandle Eastern Pipe Line Company, LP and its subsidiaries
PEPL Holdings	PEPL Holdings, LLC, a wholly-owned subsidiary of Southern Union, which owns the general partner and 100% of the limited partner interests in Panhandle Eastern Pipeline Company
PES	Philadelphia Energy Solutions
PHMSA	Pipeline Hazardous Materials Safety Administration
Preferred Units	ETE’s Series A Convertible Preferred Units
Propane Business	Heritage Operating, L.P. and Titan Energy Partners, L.P.
Propane Contribution	ETP’s contribution of its Propane Business to AmeriGas
Regency	Regency Energy Partners LP
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
Southern Union Merger	ETE’s acquisition of Southern Union on March 26, 2012
SUGS	Southern Union Gas Services
Sunoco	Sunoco, Inc.
Sunoco Logistics	Sunoco Logistics Partners L.P.
Sunoco Merger	ETP’s acquisition of Sunoco on October 5, 2012
Transwestern	Transwestern Pipeline Company, LLC
WTI	West Texas Intermediate Crude

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, 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 of ETP’s Propane Business and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

iii

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	621		$	372
Accounts receivable, net	3,318			3,057
Accounts receivable from related companies	82			71
Inventories	1,641			1,522
Exchanges receivable	50			55
Price risk management assets	54			25
Current assets held for sale	102			184
Other current assets	285			311
Total current assets	6,153			5,597
PROPERTY, PLANT AND EQUIPMENT	31,848			30,388
ACCUMULATED DEPRECIATION	(2,661		)	(2,104		)
	29,187			28,284
NON-CURRENT ASSETS HELD FOR SALE	1,000			985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,640			4,737
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	24			43
GOODWILL	6,372			6,434
INTANGIBLE ASSETS, net	2,221			2,291
OTHER NON-CURRENT ASSETS, net	546			533
Total assets	$	50,143		$	48,904

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

1

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)

	June 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,385		$	3,107
Accounts payable to related companies	14			15
Exchanges payable	153			156
Price risk management liabilities	57			115
Accrued and other current liabilities	1,542			1,754
Current maturities of long-term debt	899			613
Current liabilities held for sale	75			85
Total current liabilities	6,125			5,845
NON-CURRENT LIABILTIES HELD FOR SALE	140			142
LONG-TERM DEBT, less current maturities	21,860			21,440
PREFERRED UNITS	—			331
DEFERRED INCOME TAXES	3,861			3,566
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	135			162
OTHER NON-CURRENT LIABILITIES	849			995
COMMITMENTS AND CONTINGENCIES (Note 14)
PREFERRED UNITS OF SUBSIDIARY	73			73
EQUITY:
General Partner	(2		)	—
Limited Partners:
Common Unitholders	1,485			2,125
Accumulated other comprehensive loss	(2		)	(12		)
Total partners’ capital	1,481			2,113
Noncontrolling interest	15,619			14,237
Total equity	17,100			16,350
Total liabilities and equity	$	50,143		$	48,904

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

2

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
REVENUES:
Natural gas sales	$	864		$	554		$	1,837		$	1,057
NGL sales	787			592			1,500			1,120
Crude sales	3,992			—			7,193			—
Gathering, transportation and other fees	815			596			1,555			1,085
Refined product sales	4,650			—			9,312			—
Other	955			135			1,845			285
Total revenues	12,063			1,877			23,242			3,547
COSTS AND EXPENSES:
Cost of products sold	10,565			962			20,372			1,977
Operating expenses	375			236			724			406
Depreciation and amortization	318			206			630			360
Selling, general and administrative	161			108			341			255
Total costs and expenses	11,419			1,512			22,067			2,998
OPERATING INCOME	644			365			1,175			549
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(305		)	(282		)	(615		)	(495		)
Bridge loan related fees	—			—			—			(62		)
Equity in earnings of unconsolidated affiliates	54			22			144			97
Gain on deconsolidation of Propane Business	—			1			—			1,057
Losses on extinguishment of debt	(7		)	(8		)	(7		)	(123		)
Gains (losses) on interest rate derivatives	46			(44		)	52			(17		)
Other, net	(14		)	19			(33		)	31
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	418			73			716			1,037
Income tax expense from continuing operations	89			5			87			7
INCOME FROM CONTINUING OPERATIONS	329			68			629			1,030
Income from discontinued operations	9			7			31			6
NET INCOME	338			75			660			1,036
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	211			21			443			816
NET INCOME ATTRIBUTABLE TO PARTNERS	127			54			217			220
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—			—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	127		$	54		$	217		$	219
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.44		$	0.18		$	0.72		$	0.85
Diluted	$	0.44		$	0.18		$	0.72		$	0.84
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.45		$	0.19		$	0.77		$	0.87
Diluted	$	0.45		$	0.19		$	0.77		$	0.86

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

3

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Net income	$	338		$	75		$	660		$	1,036
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	(1		)	(8		)	(2		)	(8		)
Change in value of derivative instruments accounted for as cash flow hedges	6			(1		)	8			21
Change in value of available-for-sale securities	(1		)	—			—			—
Actuarial gain relating to pension and other postretirement benefits	2			—			1			—
Foreign currency translation adjustment	—			—			(1		)	—
Change in other comprehensive income from equity investments	(3		)	(22		)	4			(22		)
	3			(31		)	10			(9		)
Comprehensive income	341			44			670			1,027
Less: Comprehensive income attributable to noncontrolling interest	209			(4		)	447			806
Comprehensive income attributable to partners	$	132		$	48		$	223		$	221

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

4

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2013

(Dollars in millions)

(unaudited)

	General Partner			Common Unitholders			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance, December 31, 2012	$	—		$	2,125		$	(12	)	$	14,237		$	16,350
Distributions to partners	(1		)	(359		)	—			—			(360		)
Distributions to noncontrolling interest	—			—			—			(684		)	(684		)
Subsidiary units issued for cash	—			142			—			1,076			1,218
Subsidiary units issued in certain acquisitions	(1		)	(506		)	—			507			—
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			—			26			26
Capital contributions from noncontrolling interest	—			—			—			12			12
Other, net	—			(1		)	4			(2		)	1
Deemed distribution related to SUGS Transaction	—			(133		)	—			—			(133		)
Other comprehensive income, net of tax	—			—			6			4			10
Net income	—			217			—			443			660
Balance, June 30, 2013	$	(2	)	$	1,485		$	(2	)	$	15,619		$	17,100

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

5

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	660		$	1,036
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	630			360
Deferred income taxes	68			4
Gain on curtailment of other postretirement benefit plans	—			(15		)
Amortization of finance costs charged to interest	(33		)	6
Bridge loan related fees	—			62
Non-cash compensation expense	27			24
Gain on deconsolidation of Propane Business	—			(1,057		)
Losses on disposal of assets	5			2
Losses on extinguishment of debt	7			123
LIFO valuation adjustment	(16		)	—
Equity in earnings of unconsolidated affiliates	(144		)	(97		)
Distributions from unconsolidated affiliates	191			101
Other non-cash	25			29
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation (see Note 2)	(293		)	(153		)
Net cash provided by operating activities	1,127			425
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Southern Union Merger, net of cash received	—			(2,972		)
Cash paid for all other acquisitions, net of cash received	(5		)	(10		)
Capital expenditures (excluding allowance for equity funds used during construction)	(1,504		)	(1,294		)
Contributions in aid of construction costs	11			12
Contributions to unconsolidated affiliates	(2		)	(20		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	59			76
Proceeds from the sale of assets	53			34
Cash proceeds from contribution of propane operations	—			1,443
Other	(46		)	(2		)
Net cash used in investing activities	(1,434		)	(2,733		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	6,063			5,964
Repayments of long-term debt	(5,305		)	(3,101		)
Subsidiary equity offerings, net of issue costs	1,218			390
Distributions to partners	(360		)	(315		)
Debt issuance costs	(37		)	(98		)
Distributions to noncontrolling interest	(684		)	(447		)
Capital contributions received from noncontrolling interest	12			10
Redemption of Preferred Units	(340		)	—
Other, net	(11		)	(3		)
Net cash provided by financing activities	556			2,400
INCREASE IN CASH AND CASH EQUIVALENTS	249			92
CASH AND CASH EQUIVALENTS, beginning of period	372			126
CASH AND CASH EQUIVALENTS, end of period	$	621		$	218

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”); and

• ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.

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. 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 19 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’s 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.

• Energy Transfer Interstate Holdings, LLC, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which 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

▪ 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.

▪ Holdco, a Delaware limited liability company that indirectly owns Southern Union and Sunoco. As discussed in Note 2, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. Sunoco and Southern Union operations are described as follows:

◦ Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation, storage and distribution of natural gas in the United States. As discussed in Note 2, 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.

◦ Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores primarily on the east coast and in the midwest region of the United States.

• Regency is a publicly traded partnership engaged in the gathering and processing, contract 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 Haynesville, Eagle Ford, Barnett, Fayetteville, Bone Spring, Avalon and Marcellus shales, as well as the Permian Delaware basin and the mid-continent region. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

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.

• 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, 2012, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of June 30, 2013 and for the three months ended June 30, 2013 and 2012, 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 June 30, 2013, and the Partnership’s results of operations and cash flows for the three and six months endedJune 30, 2013 and 2012. 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, 2012, as filed with the SEC on March 1, 2013.

Certain prior period amounts have been reclassified to conform to the 2013 presentation. These reclassifications had no impact on net income or total equity.

As a result of the Southern Union Merger in March 2012 and the Holdco Transaction in October 2012, the periods presented herein do not include activities from Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

8

2. ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Sale of Distribution Operations

In December 2012, Southern Union entered into definitive purchase and sale agreements dated December 14, 2012 (collectively, the “Purchase and Sale Agreements”) with each of Plaza Missouri Acquisition, Inc. (“Laclede Missouri”) and Plaza Massachusetts Acquisition, Inc. (“Laclede Massachusetts”), both of which are subsidiaries of The Laclede Group, Inc. (together, the “Laclede Entities”), pursuant to which Laclede Missouri has agreed to acquire the assets of Southern Union’s Missouri Gas Energy division, and Laclede Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division. Total consideration for the acquisitions will be $1.04 billion, subject to customary closing adjustments, less the assumption of $19 million of debt. In February 2013, the Laclede Entities entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that will allow a subsidiary of APUC to assume the right of the Laclede Entities to purchase the assets of Southern Union’s New England Gas Company division, subject to certain approvals. The sale of Southern Union’s Missouri Gas Energy division is expected to close on or after September 1, 2013. The sale of Southern Union’s New England Gas Company division is expected to close in the fourth quarter of 2013.

For the three and six months ended June 30, 2013 and the period from March 26, 2012 to June 30, 2012, the distribution operations have been classified as discontinued operations in the consolidated statements of operations. The assets and liabilities of the disposal group have been classified as assets and liabilities held for sale as of June 30, 2013 and December 31, 2012.

SUGS Contribution

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”). The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, a wholly-owned subsidiary of Southern Union, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “Holdco Acquisition”). As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.

Sunoco Merger

On October 5, 2012, Sam Acquisition Corporation, a Pennsylvania corporation and a wholly-owned subsidiary of ETP, completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and $2.6 billion in cash.

Management is continuing to validate certain assumptions made in connection with the purchase price allocation of Sunoco; therefore, certain assets and/or liabilities may be adjusted.

9

3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

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

• AmeriGas. ETP owned approximately 30 million AmeriGas common units as of June 30, 2013. On July 12, 2013, ETP sold 7.5 million of its AmeriGas common units, which were received in connection with the Partnership’s contribution of its retail propane operations to AmeriGas in January 2012, for net proceeds of $346 million.

• Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, an approximate 5,400 mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc.

• FEP. ETP owns a 50% interest in the FEP, which owns an approximately 185-mile 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 a 450-mile intrastate pipeline system.

• MEP. Regency owns a 50% interest in MEP, which owns approximately 500 miles of 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.

• PES. Sunoco owns an approximate 30% non-operating interest in PES, a joint venture with The Carlyle Group, L.P., which owns a refinery in Philadelphia. Sunoco has a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Revenue	$	5,356	$	1,045	$	9,502	$	2,411
Operating income	291		220		640		534
Net income	158		50		388		265

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

10

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 are as follows:

	Six Months Ended June 30,
	2013			2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	538		$	485
Accrued advances to affiliates	$	—		$	4
Net losses from subsidiary common unit transactions	$	(364	)	$	(14	)
AmeriGas limited partner interest received in Propane Contribution	$	—		$	1,123
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger	$	—		$	2,354
Subsidiary issuances of common units in connection with certain acquisitions	$	—		$	112

5. INVENTORIES:

Inventories consisted of the following:

	June 30, 2013		December 31, 2012
Natural gas and NGLs	$	357	$	338
Crude oil	548		418
Refined products	531		572
Other	205		194
Total inventories	$	1,641	$	1,522

ETP utilizes commodity derivatives to manage price volatility associated with 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 marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units 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 marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements, 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. At December 31, 2012, the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.

Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of June 30, 2013 and December 31,

11

2012 was $23.59 billion and $24.15 billion, respectively. As of June 30, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $22.76 billion and $22.05 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 June 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:

	Fair Value Measurements at June 30, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	40		$	—		$	40		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	76			68			8			—
Options — Calls	1			—			1			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Forwards/Swaps	20			16			4			—
Power:
Forwards	9			—			9			—
Futures	2			2			—
Options — Calls	8			—			8			—
Total commodity derivatives	128			91			37			—
Total Assets	$	168		$	91		$	77		$	—
Liabilities:
Interest rate derivatives	$	(122	)	$	—		$	(122	)	$	—
Embedded derivatives in the Regency Preferred Units	(47		)	—			—			(47		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(9		)	(9		)	—			—
Swing Swaps IFERC	(4		)	—			(4		)	—
Fixed Swaps/Futures	(59		)	(54		)	(5		)	—
Options — Calls	(1		)	—			(1		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(7		)	(6		)	(1		)	—
Power:
Forwards	(9		)	—			(9		)	—
Futures	(2		)	(2		)	—			—
Options — Calls	(5		)	—			(5		)	—
Crude	(1		)	(1		)	—			—
Total commodity derivatives	(98		)	(72		)	(26		)	—
Total Liabilities	$	(267	)	$	(72	)	$	(148	)	$	(47	)

12

	Fair Value Measurements at December 31, 2012
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	55		$	—		$	55		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	11			11			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	98			94			4			—
Options — Calls	3			—			3			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Swaps	2			1			1			—
Power:
Forwards	27			—			27			—
Futures	1			1			—			—
Options — Calls	2			—			2			—
Refined Products	5			1			4			—
Total commodity derivatives	156			108			48			—
Total Assets	$	211		$	108		$	103		$	—
Liabilities:
Interest rate derivatives	$	(235	)	$	—		$	(235	)	$	—
Preferred Units	(331		)	—			—			(331		)
Embedded derivatives in the Regency Preferred Units	(25		)	—			—			(25		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(2		)	—			(2		)	—
Fixed Swaps/Futures	(103		)	(94		)	(9		)	—
Options — Calls	(3		)	—			(3		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Swaps	(4		)	(3		)	(1		)	—
Power:
Forwards	(27		)	—			(27		)	—
Futures	(2		)	(2		)	—			—
Refined Products	(8		)	(1		)	(7		)	—
Total commodity derivatives	(168		)	(118		)	(50		)	—
Total Liabilities	$	(759	)	$	(118	)	$	(285	)	$	(356	)

13

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the six months ended June 30, 2013. There were no transfers between the fair value hierarchy levels during the six months ended June 30, 2013 or 2012.

Balance, December 31, 2012	$	(356	)
Realized loss included in other income (expense)	(9		)
Net unrealized loss included in other income (expense)	(22		)
Redemption of Preferred Units	340
Balance, June 30, 2013	$	(47	)

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Income from continuing operations	$	329	$	68	$	629	$	1,030
Less: Income from continuing operations attributable to noncontrolling interest	206		19		428		815
Income from continuing operations, net of noncontrolling interest	123		49		201		215
Less: General Partner’s interest in income from continuing operations	—		—		—		1
Income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	214
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	280.5		280.0		280.2		253.3
Basic income from continuing operations per Limited Partner unit	$	0.44	$	0.18	$	0.72	$	0.85
Basic income from discontinued operations per Limited Partner unit	$	0.01	$	0.01	$	0.05	$	0.02
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	214
Dilutive effect of equity-based compensation of subsidiaries	—		—		—		(1		)
Diluted income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	213
Weighted average limited partner units	280.5		280.0		280.2		253.3
Diluted income from continuing operations per Limited Partner unit	$	0.44	$	0.18	$	0.72	$	0.84
Diluted income from discontinued operations per Limited Partner unit	$	0.01	$	0.01	$	0.05	$	0.02

8. DEBT OBLIGATIONS:

ETE Term Loan

On March 23, 2012, ETE entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, as Administrative Agent, and the other lenders from time to time party thereto (the “Term Lenders”), which became effective on March 26, 2012. The Term Credit Agreement has a scheduled maturity date of March 26, 2017, with an option

14

for ETE to extend the term subject to the terms and conditions set forth therein. Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2 billion. Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of ETE for each interest period. The applicable margin for LIBOR rate loans is 3.00% and the applicable margin for base rate loans is 2.00%.  Proceeds of the borrowings under the Term Credit Agreement were used to partially fund the Southern Union Merger, to repay amounts outstanding under the Parent Company Credit Facility, and to pay transaction fees and expenses related to the Southern Union Merger, the new Term Credit Agreement and other transactions incidental thereto.

During the three months ended June 30, 2013, proceeds from ETP’s acquisition of ETE’s 60% interest in Holdco were used to repay borrowings of $1.10 billion on ETE’s Term Credit Agreement. The total amount outstanding as of June 30, 2013 was $900 million.

Senior Notes

Regency Senior Notes

In April 2013, in conjunction with Southern Union’s contribution of SUGS to Regency, Regency issued $600 million senior notes in a private placement that mature on November 1, 2023 and bear interest at 4.5% payable semi-annually. In April 3013, Regency also delivered notice of redemption to the holders of its 2016 Senior Notes. In June 2013, Regency redeemed all of the $163 million outstanding 9.375% Senior Notes due 2016 for $178 million cash, including accrued and unpaid interest of $7 million and other fees and expenses.

ETP Senior Notes

In January 2013, ETP issued $800 million of 3.6% Senior Notes due February 2023 and $450 million of 5.15% Senior Notes due February 2043. ETP used the net proceeds of $1.24 billion from the offering to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.

Sunoco Logistics Senior Notes

In January 2013, Sunoco Logistics issued $350 million of 3.45% Senior Notes due January 2023 and $350 million of 4.95% Senior Notes due January 2043. The net proceeds of $691 million from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facilities and for general partnership purposes.

ETP Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion total principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066.  These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates.  In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.

Revolving Credit Facilities

Parent Company Credit Facility

As of June 30, 2013, there were no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.

ETP Credit Facility

ETP has a $2.5 billion revolving credit facility (the “ETP Credit Facility”) that expires in October 2016. 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 ETP’s current and future unsecured debt.

As of June 30, 2013, the ETP Credit Facility had a balance of $900 million outstanding and the amount available for future borrowings was $1.49 billion after taking into account letters of credit of $107 million. The weighted average interest rate on the total amount outstanding as of June 30, 2013 was 1.70%.

15

Regency Credit Facility

In May 2013, Regency entered into an agreement to increase the borrowing capacity of the Regency Credit Facility to $1.2 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018.

As of June 30, 2013, the Regency Credit Facility had a balance outstanding of $535 million in revolving credit loans and approximately $13 million in letters of credit. The total amount available under the Regency Credit Facility, as of June 30, 2013, which was reduced by any letters of credit, was approximately $652 million, and the weighted average interest rate on the total amount outstanding as of June 30, 2013 was 2.20%.

Southern Union Credit Facilities

Proceeds from the SUGS Contribution were used to repay $240 million of borrowings under the Eighth Amended and Restated Revolving Credit Agreement (the “Southern Union Credit Facility”) and the facility was terminated.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains two credit facilities to fund its working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 and a $200 million unsecured credit facility which expires in August 2013. There were no outstanding borrowings under these credit facilities as of June 30, 2013.

West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility. Outstanding borrowings under this credit facility were $35 million as of June 30, 2013.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of June 30, 2013.

9. PREFERRED UNITS:

On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units from Regency GP Acquirer L.P. (“GE Regency”) pursuant to a Preferred Unit Redemption Agreement, dated as of March 28, 2013, between ETE and GE Regency. Prior to the Redemption, on March 28, 2013, ETE paid GE Regency $40 million in cash in exchange for GE Regency relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.

10. EQUITY:

ETE Common Units Issued

The change in ETE Common Units during the six months ended June 30, 2013 was as follows:

	Number of Units
Outstanding at December 31, 2012	280.0
Issuance of restricted units under equity incentive plans	0.8
Outstanding at June 30, 2013	280.8

Sales of Common Units by Subsidiaries

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

As a result of ETP’s and Regency’s issuances of common units during the six months ended June 30, 2013, we recognized decreases in partners’ capital of $364 million.

Sales of Common Units by ETP

In January 2013 and May 2013, ETP entered into Equity Distribution Agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During

16

the six months ended June 30,2013, ETP received proceeds of $387 million, net of commissions of $4 million, from the issuance of units pursuant to the Equity Distribution Agreements, which proceeds were used for general partnership purposes. ETP also received $26 million net of commissions, in July 2013 from the settlement of transactions initiated in June 2013 under these agreements. Approximately $609 million of ETP Common Units remain available to be issued under these agreements.

During the six months ended June 30,2013, distributions of $46 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 1.0 million ETP Common Units. As of June 30, 2013, a total of 3.3 million ETP Common Units remain available to be issued under the existing registration statement.

In April 2013, ETP issued 13.8 million ETP Common Units at $48.05 per ETP Common Unit in an underwritten public offering. Proceeds, net of commissions, of $657 million from the offering were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes.

ETP Class G Units

In April 2013, all of the outstanding ETP Class F Units, which were issued in connection with the Sunoco Merger, were exchanged for ETP Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in ETP’s consolidated financial statements.

ETP Class H Units

On August 7, 2013, ETP, ETE and ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE (“ETE Holdings”) entered into an Exchange and Redemption Agreement, pursuant to which ETP has agreed to redeem and cancel 50.2 million of its common units representing limited partner interests (the “Redeemed Units”) currently owned by ETE Holdings in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”) which will generally be entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50% of the profits, losses, and other items allocated to ETP by Sunoco Partners LLC (“Sunoco Partners”), the general partner of Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ending September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Quarterly Distributions of Available Cash” below.

This transaction is subject to certain customary closing conditions. In the Exchange and Redemption Agreement, ETP, ETE and ETE Holdings have made customary representations and warranties and have agreed to customary covenants relating to this transaction.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 19, 2013	$	0.635
March 31, 2013	May 6, 2013	May 17, 2013	0.645
June 30, 2013	August 5, 2013	August 19, 2013	0.655

17

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.89375
March 31, 2013	May 6, 2013	May 15, 2013	0.89375
June 30, 2013	August 5, 2013	August 14, 2013	0.89375

Following are incentive distributions ETE has agreed to relinquish:

• In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of the incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.

• In conjunction with the Holdco transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.

• As discussed in Note 2, in connection with ETP’s acquisition of ETE’s 60% interest in Holdco on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.

As discussed under “Class H Units” above, ETP has agreed to make incremental cash distributions of $329 million over 15 quarters, commencing with the quarter ending September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition.

As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:

	Quarters Ending
	March 31		June 30		September 30		December 31		Total Year
2013	N/A		N/A		$	21.00	$	21.00	$	42.00
2014	$	27.25	$	27.25	27.25		27.25		109.00
2015	13.25		13.25		13.25		13.25		53.00
2016	5.50		5.50		5.50		5.50		22.00

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.460
March 31, 2013	May 6, 2013	May 13, 2013	0.460
June 30, 2013	August 5, 2013	August 14, 2013	0.465

In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego incentive distributions with respect to the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 8, 2013	February 14, 2013	$	0.5450
March 31, 2013	May 9, 2013	May 15, 2013	0.5725
June 30, 2013	August 8, 2013	August 14, 2013	0.6000

18

Accumulated Other Comprehensive Loss

The following table presents the components of accumulated other comprehensive loss, net of tax:

	June 30, 2013			December 31, 2012
Net gains (losses) on commodity related hedges	$	6		$	(3	)
Foreign currency translation adjustment	(1		)	—
Actuarial loss related to pensions and other postretirement benefits	(9		)	(10		)
Equity investments, net	(5		)	(9		)
Subtotal	(9		)	(22		)
Amounts attributable to noncontrolling interest	7			10
Total accumulated other comprehensive loss, net of tax	$	(2	)	$	(12	)

11. UNIT-BASED COMPENSATION PLANS:

We and certain of our subsidiaries have equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase common units, restricted units, phantom units, DERs, common unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

During the six months ended June 30, 2013, 750,000 awards were granted to an ETE employee and 6,042 awards were granted to ETE directors. As of June 30, 2013 a total of 804,190 unit awards remain unvested. We expect to recognize a total of $42 million in compensation expense over a weighted average period of 4.5 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the six months ended June 30, 2013, ETP employees were granted a total of 1,074,163 unvested awards with five-year service vesting requirements, and directors were granted a total of 9,060 unvested awards with three-year and five-year service vesting requirements. The weighted average grant-date fair value of these awards was $45.37 per unit. As of June 30, 2013 a total of 2,827,915 unit awards remain unvested, including the new awards granted during the period. ETP expects to recognize $76 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.

Regency Unit-Based Compensation Plans

During the six months ended June 30, 2013, Regency employees and directors were granted 52,360 Regency phantom units with 5-year service vesting requirements. As of June 30, 2013, a total of 1,189,247 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.43 per unit. Regency expects to recognize a total of $22 million in compensation expense over a period of 5 years related to Regency’s unvested phantom units.

Sunoco Logistics Unit-Based Compensation Plan

As of June 30, 2013, a total of 936,438 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $19 million in compensation expense over a weighted-average period of 2.5 years.

12. INCOME TAXES:

The following table summarizes the Partnership’s income tax expense from continuing operations:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Income tax expense from continuing operations	$	89		$	5		$	87		$	7
Effective tax rate	21		%	7		%	12		%	1		%

The increase in the effective tax rate in the 2013 periods presented over the 2012 periods presented is primarily due to the Partnership conducting a significant portion of its activities through corporate subsidiaries, Southern Union and Sunoco. The Southern Union transaction was completed in March 2012 while the Holdco and Sunoco transactions were completed in October 2012.

19

13. 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 June 30,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	3		$	1		$	2		$	—
Interest cost	9			1			(1		)	1
Expected return on plan assets	(15		)	(1		)	(1		)	(2		)
	(3		)	1			—			(1		)
Regulatory adjustment(3)	2			(3		)	—			1
Net periodic benefit cost	$	(1	)	$	(2	)	$	—		$	—

	Six Months Ended June 30,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	5		$	1		$	2		$	—
Interest cost	18			3			(1		)	1
Expected return on plan assets	(30		)	(4		)	(1		)	(2		)
Actuarial loss amortization	1			—			—			—
Settlement credits	(2		)	—			—			—
Curtailment recognition(2)	—			—			—			(15		)
	(8		)	—			—			(16		)
Regulatory adjustment(3)	4			—			—			1
Net periodic benefit cost	$	(4	)	$	—		$	—		$	(15	)

⁽¹⁾  The three and six months ended June 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.

⁽²⁾  Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $60 million.  As such, the net curtailment gain recognition was $15 million.

⁽³⁾  In its distribution operations, Southern Union recovers 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 amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

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

FERC Audit

The FERC is currently conducting an audit of Panhandle Eastern Pipe Line Company, LP, a subsidiary of Southern Union, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial

20

reporting to the FERC, reservation charge crediting policy and record retention.  A draft audit report was received on July 19, 2013 noting no issues that would have a material impact on the Partnership’s historical financial position or results of operations.

Contingent Residual Support Agreement — AmeriGas

In connection with the closing of the contribution of ETP’s propane operations in January 2013, 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.

PEPL Holdings Guarantee of Collection

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

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 $12 million for the three months endedJune 30, 2013 and 2012, respectively, which include contingent rentals totaling $6 million in the three months ended June 30, 2013.  For the six months ended June 30, 2013 and 2012, rental expense for operating leases totaled $65 million and $19 million, respectively, which include contingent rentals totaling $10 million in the six months ended June 30, 2013.  During the three and six months ended June 30, 2013, $5 million and $10 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.

Sunoco Litigation

Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania.  Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants

21

following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.

Litigation Relating to the Southern Union Merger

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas.  The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas.  Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty.  The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.  On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  Three of the lawsuits also named Merger Sub as a defendant.  These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS.  These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery.  The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action.  On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice.  In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

The Texas case remains pending, and discovery is ongoing.

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 June 30, 2013, Sunoco was a defendant in two lawsuits involving one state and Puerto Rico.  These cases are venued in a multidistrict proceeding in a New York federal court.  Both 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.

Discovery is proceeding in these cases.  There has been insufficient information developed about the plaintiffs’ legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate 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 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.

Other Litigation and Contingencies

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”),

22

certain members of management for ETP and ETE, ETE, and Southern Union.  The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas.  Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants.  Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union.  On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action.  On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment.  Defendants filed a reply on December 19, 2012.  On December 20, 2012, the court conducted an oral hearing on the motion.  Plaintiffs filed a post-hearing sur-reply on January 7, 2013.  On January 16, 2013, the Court granted defendants’ motion for summary judgment.  The parties agreed to settle the matter and executed a memorandum of understanding. The parties are drafting a stipulation of settlement (with proposed judgment) and will have a settlement hearing likely in August 2013 for the Court to approve the settlement, which will dispose of the case. It is unlikely the Court will reject the settlement.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of June 30, 2013 and December 31, 2012, accruals of approximately $37 million and $42 million 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 June 30, 2013 or December 31, 2012 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Will Price.  Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  On September 19, 2009, the Court denied plaintiffs’ request for class certification.  Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010.  Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by the FERC.  As a result, Southern Union believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Panhandle complied with the terms of its tariffs).  Panhandle will continue to vigorously defend the case.  Southern Union believes it has no liability associated with this proceeding.

Litigation Related to Incident at JJ's Restaurant.  On February 19, 2013, there was a natural gas explosion at JJ's Restaurant located at 910 W. 48th Street in Kansas City, Missouri.  One person died and media reports indicate that up to fifteen people were transported to area hospitals.  The extent and nature of those injuries are currently unknown.  The restaurant building was destroyed in the explosion and fire.  Immediately surrounding buildings sustained damage, but the full extent of that damage is unknown at this time.  A contractor, Heartland Midwest LLC, was in the process of installing cable for Time Warner Cable and hit a natural gas line while directionally boring.  The utility locates for the work were done by USIC Locating Services, Inc., a utility infrastructure locating company engaged by Missouri Gas Energy to locate and mark underground gas lines (and engaged by others to mark other underground facilities).  Several parties have retained counsel, and to date, nine lawsuits have been filed in the Circuit Court of Jackson County, Missouri, against numerous defendants.  MGE and MGE employee, Michael Palier, are defendants in all but one of the lawsuits (Palier v. Time Warner).  The lawsuits filed to date include Simmons v. MGE, Case No. 1316-CV07265 (no trial date set); Tanner v. MGE, Case No. 1316-CV09906 (no trial date set), JJ's Restaurant v. MGE, Case No. 1316-CV11288 (two trial dates set on January 12, 2015 and April 6, 2015); Meek v. MGE, Case No. 1316-CV13523 (no trial date set); Cramer v. MGE, Case No. 1316-CV13738 (no trial date set); Plazaview, LLC v. MGE, Case No. 1316-CV16817 (no trial date set); Mingos v. MGE, Case No. 1316-CV18072 (no trial date set); Palier v. Time Warner, Case No. 1316-CV18684 (no trial date set); and Couture v. MGE, Case No. 1316-CV18787 (no trial date set).  Discovery in the pending lawsuits is ongoing.  No demands have been made in any of the pending lawsuits.  The Partnership anticipates that more lawsuits will be filed.  The Missouri Public Service Commission and the Occupational Safety and Health Administration investigations are ongoing.  The Partnership will assess its potential exposure as the matter progresses as no estimate can be made at this time.

23

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 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. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union 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.  Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities.  We are unable to estimate any losses or range of losses that could result from such developments.  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.

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.

• Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to manufactured gas plants (“MGPs”) and may also be responsible for the removal of old MGP structures.

• Currently operating Sunoco retail sites.

24

• 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 of June 30, 2013, Sunoco had been named as a PRP at 39 identified 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.

	June 30, 2013		December 31, 2012
Current	$	40	$	46
Non-current	160		166
Total environmental liabilities	$	200	$	212

During the three and six months ended June 30, 2013, the Partnership recorded $11 million and $18 million, respectively, of expenditures related to environmental cleanup programs.

The EPA’s Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities.  We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules.  Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

On August 20, 2010, the EPA published new regulations under the federal Clean Air Act (“CAA”) to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines.  The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment.  In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems.  If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations.  Compliance with the final rule is required by October 2013.

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

25

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.

15. 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 our 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). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock 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 we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use 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 our derivative instruments using mark-to-market accounting, with changes in the fair value of our 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, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. We use 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.

We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use 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.

Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. Additionally, we also have trading activities related to power in our “All Other” segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily

26

position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

Derivatives are utilized in our midstream segment in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our 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:

	June 30, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	9,650,000	2013-2015	—		—
Basis Swaps IFERC/NYMEX (1)	(37,702,500)	2013-2014	(30,980,000	)	2013-2014
Power (Megawatt):
Forwards	145,078	2013	19,650		2013
Futures	(557,260)	2013	(1,509,300	)	2013
Options — Calls	(1,200)	2013	1,656,400		2013
Crude (Bbls) — Futures	(80,000)	2013	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	8,770,000	2013-2014	150,000		2013
Swing Swaps IFERC	20,060,000	2013	(83,292,500	)	2013
Fixed Swaps/Futures	23,435,000	2013-2015	27,077,500		2013
Forward Physical Contracts	1,758,402	2013-2014	11,689,855		2013-2014
Natural Gas Liquid (Bbls):
Forwards/Swaps	(597,000)	2013-2014	(30,000	)	2013
Refined Products (Bbls) — Futures	(1,227,000)	2013	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(10,530,000)	2013	(18,655,000	)	2013
Fixed Swaps/Futures	(32,682,500)	2013	(44,272,500	)	2013
Hedged Item — Inventory	32,682,500	2013	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(2,300,000)	2013	—		—
Fixed Swaps/Futures	(4,140,000)	2013	(8,212,500	)	2013
Natural Gas Liquid (Bbls):
Forwards/Swaps	(690,000)	2013	(930,000	)	2013
Crude (Bbls) — Futures	(210,000)	2013	—		—
Refined Products (Bbls) — Futures	—	—	(98,000	)	2013

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

27

We expect gains of $6 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:

	June 30, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	18,672,000	2013-2014	8,395,000	2013-2014
Propane (Gallons):
Forwards/Swaps	20,496,000	2013	3,318,000	2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	234,000	2013-2014	243,000	2013-2014
WTI Crude Oil (Barrels):
Forwards/Swaps	700,000	2013-2014	356,000	2014

28

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. Southern Union also uses treasury rate locks to manage interest rate risk associated with long term borrowings.

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)	June 30, 2013		December 31, 2012
ETE	March 2017	Pay a fixed rate of 1.25% and receive a floating rate	$	500	$	500
ETP	July 2013 (2)	Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	100		400
ETP	July 2014 (2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	400		400
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	600		600
ETP	February 2023	Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%	400		—
Southern Union	November 2016	Pay a fixed rate of 2.91% and receive a floating rate	75		75
Southern Union	November 2021	Pay a fixed rate of 3.75% and receive a floating rate	450		450

⁽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.

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposures associated with a single or multiple counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry including petrochemical companies, consumer and industrials, oil and gas producers, municipalities, utilities and midstream companies. Our overall exposure to credit risk may be affected either positively or negatively in that the counterparties may experience similar changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

ETP utilizes master-netting agreements and has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about the settlement date for non-exchange traded derivatives. 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. ETP had net deposits with counterparties of $34 million and $41 million as of June 30, 2013 and December 31, 2012, respectively.

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 June 30, 2013 would be $13 million, which would be reduced by $1 million, due to the netting feature.

29

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

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	June 30, 2013		December 31, 2012		June 30, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	20	$	8	$	(2	)	$	(10	)
	20		8		(2		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	81	$	110	$	(80	)	$	(116	)
Commodity derivatives	91		40		(76		)	(44		)
Current assets held for sale	1		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		(5		)	(9		)
Interest rate derivatives	40		55		(122		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(47		)	(25		)
	213		207		(330		)	(429		)
Total derivatives	$	233	$	215	$	(332	)	$	(439	)

In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.

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
Contract Type	Balance Sheet Location	June 30, 2013			December 31, 2012			June 30, 2013			December 31, 2012
Bi-lateral contracts	Price risk management asset (liability)	$	82		$	28		$	(81	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	171			149			(155		)	(221		)
	Gross fair value	253			177			(236		)	(248		)
Collateral paid to OTC counterparties	Other current assets (liabilities)	—			—			—			2
Counterparty netting	Price risk management asset (liability)	(63		)	(25		)	63			25
Payments on margin deposit	Other current assets (liabilities)	(11		)	—			16			59
	Net fair value	179			152			(157		)	(162		)
	Other derivatives – gross	54			63			(175		)	(277		)
	Total derivatives	$	233		$	215		$	(332	)	$	(439	)

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.

30

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	6	$	(17	)	$	8	$	5
Interest rate derivatives	—		20			—		20
Total	$	6	$	3		$	8	$	25

	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 June 30,				Six Months Ended June 30,
		2013		2012		2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	1	$	13	$	2	$	16
Total		$	1	$	13	$	2	$	16

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,					Six Months Ended June 30,
		2013			2012		2013		2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(1	)	$	32	$	4	$	19
Total		$	(1	)	$	32	$	4	$	19

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2013			2012			2013			2012
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	3		$	—		$	(1	)	$	(11	)
Commodity derivatives — Non-Trading	Cost of products sold	35			12			14			12
Commodity derivatives — Non-Trading	Deferred gas purchases	2			—			(3		)	—
Interest rate derivatives	Gains (losses) on interest rate derivatives	46			(44		)	52			(17		)
Embedded derivatives	Other income	(8		)	8			(22		)	8
Total		$	78		$	(24	)	$	40		$	(8	)

31

16. 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 (see Note 18).

17. OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:

	June 30, 2013		December 31, 2012
Deposits paid to vendors	$	34	$	41
Prepaid expenses and other	251		270
Total other current assets	$	285	$	311

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	June 30, 2013		December 31, 2012
Interest payable	$	323	$	334
Customer advances and deposits	99		61
Accrued capital expenditures	402		427
Accrued wages and benefits	123		250
Taxes payable other than income taxes	273		208
Income taxes payable	37		41
Deferred income taxes	84		130
Other	201		303
Total accrued and other current liabilities	$	1,542	$	1,754

32

18. REPORTABLE SEGMENTS:

As a result of the Holdco Acquisition in April 2013, 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; 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 previously reported net income as a measure of segment performance. Due to the change in our reportable segments described above, the financial information available to our chief operating decision maker to assess the performance is now based on Segment Adjusted EBITDA. Therefore, we have accordingly revised our segment operating performance measure that we report. 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 includes 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 segment performance measure, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

As discussed in Note 2, 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 reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.

• ETP’s Segment Adjusted ABITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Because 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 include the results of SUGS from March 26, 2012 to April 30, 2013.

33

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Segment Adjusted EBITDA:
Investment in ETP	$	1,069		$	642		$	2,025		$	1,136
Investment in Regency	153			137			274			257
Corporate and Other	(23		)	(10		)	(29		)	(41		)
Adjustments and Eliminations	(36		)	(41		)	(55		)	(43		)
Total	1,163			728			2,215			1,309
Depreciation and amortization	(318		)	(206		)	(630		)	(360		)
Interest expense, net of interest capitalized	(305		)	(282		)	(615		)	(495		)
Bridge loan related fees	—			—			—			(62		)
Gain on deconsolidation of Propane Business	—			1			—			1,057
Gains (losses) on interest rate derivatives	46			(44		)	52			(17		)
Non-cash unit-based compensation expense	(11		)	(12		)	(27		)	(24		)
Unrealized gains (losses) on commodity risk management activities	22			37			23			(47		)
Losses on extinguishment of debt	(7		)	(8		)	(7		)	(123		)
Gain on curtailment of other postretirement benefit plans	—			—			—			15
LIFO valuation adjustment	(22		)	—			16			—
Equity in earnings of unconsolidated affiliates	54			22			144			97
Adjusted EBITDA related to unconsolidated affiliates	(184		)	(140		)	(388		)	(281		)
Adjusted EBITDA related to discontinued operations	(23		)	(27		)	(63		)	(34		)
Other, net	3			4			(4		)	2
Income from continuing operations before income tax expense	$	418		$	73		$	716		$	1,037

	June 30, 2013			December 31, 2012
Total assets:
Investment in ETP	$	43,651		$	43,320
Investment in Regency	8,521			8,123
Corporate and Other	704			707
Adjustments and Eliminations	(2,733		)	(3,246		)
Total	$	50,143		$	48,904

34

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues:
Investment in ETP:
Revenues from external customers	$	11,529		$	1,584		$	22,366		$	2,903
Intersegment revenues	22			12			39			16
	11,551			1,596			22,405			2,919
Investment in Regency:
Revenues from external customers	628			509			1,163			880
Intersegment revenues	11			2			16			6
	639			511			1,179			886
Corporate and Other:
Revenues from external customers	—			4			—			2
Adjustments and Eliminations	(127		)	(234		)	(342		)	(260		)
Total revenues	$	12,063		$	1,877		$	23,242		$	3,547

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

Investment in ETP

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Intrastate Transportation and Storage	$	558	$	452	$	1,209	$	899
Interstate Transportation and Storage	354		310		677		452
Midstream	588		629		1,338		1,088
NGL Transportation and Services	420		148		766		302
Investment in Sunoco Logistics	4,256		—		7,713		—
Retail Marketing	5,291		—		10,508		—
All Other	84		57		194		178
Total revenues	11,551		1,596		22,405		2,919
Less: Intersegment revenues	22		12		39		16
Revenues from external customers	$	11,529	$	1,584	$	22,366	$	2,903

Investment in Regency

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Gathering and Processing	$	583	$	462	$	1,069	$	787
Contract Services	52		44		101		90
Corporate and others	4		5		9		9
Total revenues	639		511		1,179		886
Less: Intersegment revenues	11		2		16		6
Revenues from external customers	$	628	$	509	$	1,163	$	880

35

19. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS

(unaudited)

	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	72		$	9
Accounts receivable from related companies	8			11
Other current assets	1			3
Total current assets	81			23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,080			6,094
INTANGIBLE ASSETS, net	16			19
GOODWILL	9			9
NOTE RECEIVABLE FROM AFFILIATE	—			166
OTHER NON-CURRENT ASSETS, net	53			56
Total assets	$	4,239		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	24			15
Interest payable	29			48
Price risk management liabilities	5			5
Accrued and other current liabilities	13			1
Current maturities of long-term debt	4			4
Total current liabilities	75			74
LONG-TERM DEBT, less current maturities	2,682			3,840
PREFERRED UNITS	—			331
OTHER NON-CURRENT LIABILITIES	1			9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(2		)	—
Limited Partners	1,485			2,125
Accumulated other comprehensive loss	(2		)	(12		)
Total partners’ capital	1,481			2,113
Total liabilities and partners’ capital	$	4,239		$	6,367

36

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(23	)	$	(10	)	$	(29	)	$	(41	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(53		)	(63		)	(117		)	(106		)
Bridge loan related fees	—			—			—			(62		)
Gains (losses) on interest rate derivatives	6			(9		)	6			(9		)
Equity in earnings of unconsolidated affiliates	198			127			366			434
Other, net	(2		)	9			(10		)	4
INCOME BEFORE INCOME TAXES	126			54			216			220
Income tax benefit	(1		)	—			(1		)	—
NET INCOME	127			54			217			220
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—			—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	127		$	54		$	217		$	219

37

STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
	2013			2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	427		$	203
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds received in (paid for) acquisitions and other transactions, net	1,332			(1,113		)
Contributions to affiliate	—			(445		)
Note receivable from affiliate	—			(221		)
Payments received on note receivable from affiliate	166			55
Net cash provided by (used in) investing activities	1,498			(1,724		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	440			2,005
Principal payments on debt	(1,602		)	(107		)
Distributions to partners	(360		)	(315		)
Redemption of Preferred Units	(340		)	—
Debt issuance costs	—			(77		)
Net cash provided by (used in) financing activities	(1,862		)	1,506
DECREASE IN CASH AND CASH EQUIVALENTS	63			(15		)
CASH AND CASH EQUIVALENTS, beginning of period	9			18
CASH AND CASH EQUIVALENTS, end of period	$	72		$	3

38

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

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts 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, 2012 filed with the SEC on March 1, 2013. 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, 2012.

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 and Regency. 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 June 30, 2013, our interests in ETP and Regency consisted of:

	General Partner Interest (as a % of total partnership  interest)		IDRs		Common Units
ETP	0.8	%	100	%	99.7
Regency	1.3	%	100	%	26.3

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. 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.

Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and NGL businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.

As a result of the Holdco Acquisition in April 2013, 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.

• 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. ETP also controls Holdco.

RECENT DEVELOPMENTS

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency of all the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern

39

Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. Upon the closing of the transaction, ETE agreed to forego incentive distributions with respect to the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. As a result, ETP now owns 100% of Holdco.

Equity Offering

In April 2013, ETP issued 13.8 million Common Units at $48.05 per Common Unit in a public offering. Net proceeds of $657 million from the offering were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes.

Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion total principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066.  These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.

Sale of AmeriGas Common Units

On July 12, 2013, ETP received $346 million in net proceeds from the sale of 7.5 million of its AmeriGas common units, which were received in connection with ETP’s contribution of its retail propane operations to AmeriGas in January 2012. Net proceeds from this sale were used to repay borrowings under the ETP Credit Facility.

Class H Units

On August 7, 2013, ETP, ETE and ETE Holdings entered into an Exchange and Redemption Agreement, pursuant to which ETP has agreed to redeem and cancel 50.2 million of its common units representing limited partner interests currently owned by ETE Holdings in exchange for the issuance by ETP to ETE Holdings of the new Class H Units of limited partner interest in ETP which will generally be entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50% of the profits, losses, and other items allocated to ETP by Sunoco Partners, the general partner of Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ending September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Cash Distributions” below.

This transaction is subject to certain customary closing conditions. In the Exchange and Redemption Agreement, ETP, ETE and ETE Holdings have made customary representations and warranties and have agreed to customary covenants relating to this transaction.

In connection with this transaction, ETP has agreed to make incremental cash distributions of $329 million over 15 quarters, commencing with the quarter ending September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the

40

Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. As a result, the net IDR subsidies from ETE to ETP, taking into account the incremental cash distributions related to the Class H Units as an offset thereto will be $21 million with respect to each of the quarters ending September 30, 2013 and December 31, 2013, a total of $109 million during 2014, a total of $53 million during 2015 and a total of $22 million during 2016.

LNG Export License

On August 7, 2013, Lake Charles Exports, LLC, an entity owned by BG Group plc and Trunkline LNG Export, LLC (a joint venture owned by ETP and ETE), received an order from the Department of Energy conditionally granting authorization to export up to 2.0 Bcf/d of natural gas in the form of  LNG to non-free trade agreement countries from the existing LNG import terminal owned by Trunkline LNG Company, LLC (an indirect wholly-owned subsidiary of ETP) which is located in Lake Charles, Louisiana.  Lake Charles Exports, LLC previously received approval to export LNG from the Lake Charles facility to free trade agreement countries on July 22, 2011.

Results of Operations

We previously reported net income as a measure of segment performance. We have revised certain reports provided to our chief operating decision maker to assess the performance of our business to reflect Segment Adjusted EBITDA. 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 includes 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 segment performance measure, we have adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation.

As discussed in Note 2, 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.

41

Consolidated Results

	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,069		$	642		$	427		$	2,025		$	1,136		$	889
Investment in Regency	153			137			16			274			257			17
Corporate and Other	(23		)	(10		)	(13		)	(29		)	(41		)	12
Adjustments and Eliminations (1)	(36		)	(41		)	5			(55		)	(43		)	(12		)
Total	1,163			728			435			2,215			1,309			906
Depreciation and amortization	(318		)	(206		)	(112		)	(630		)	(360		)	(270		)
Interest expense, net of interest capitalized	(305		)	(282		)	(23		)	(615		)	(495		)	(120		)
Bridge loan related fees	—			—			—			—			(62		)	62
Gain on deconsolidation of Propane Business	—			1			(1		)	—			1,057			(1,057		)
Gains (losses) on interest rate derivatives	46			(44		)	90			52			(17		)	69
Non-cash unit-based compensation expense	(11		)	(12		)	1			(27		)	(24		)	(3		)
Unrealized gains (losses) on commodity risk management activities	22			37			(15		)	23			(47		)	70
Losses on extinguishment of debt	(7		)	(8		)	1			(7		)	(123		)	116
Gain on curtailment of other postretirement benefit plans	—			—			—			—			15			(15		)
LIFO valuation adjustment	(22		)	—			(22		)	16			—			16
Equity in earnings of unconsolidated affiliates	54			22			32			144			97			47
Adjusted EBITDA related to unconsolidated affiliates	(184		)	(140		)	(44		)	(388		)	(281		)	(107		)
Adjusted EBITDA related to discontinued operations	(23		)	(27		)	4			(63		)	(34		)	(29		)
Other, net	3			4			(1		)	(4		)	2			(6		)
Income from continuing operations before income tax expense	418			73			345			716			1,037			(321		)
Income tax expense from continuing operations	89			5			84			87			7			80
Income from continuing operations	329			68			261			629			1,030			(401		)
Income from discontinued operations	9			7			2			31			6			25
Net income	$	338		$	75		$	263		$	660		$	1,036		$	(376	)

⁽¹⁾  See description of eliminations included in Note 18 to our consolidated financial statements.

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 June 30, 2013 increased primarily due to the following:

• depreciation and amortization related to Sunoco Logistics and Sunoco of $90 million; and

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

Depreciation and amortization for the six months ended June 30, 2013 increased primarily due to the following:

• depreciation and amortization related to Southern Union, which was acquired March 26, 2012 and resulted in increased depreciation and amortization of $36 million;

• depreciation and amortization related to Sunoco Logistics and Sunoco of $182 million; and

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

42

Interest Expense, Net of Interest Capitalized. Interest expense for the three months ended June 30, 2013 increased primarily due to the following:

• interest expense related to Sunoco Logistics and Sunoco of $25 million;

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

• an increase of $13 million related to Regency primarily due to its issuance of $700 million senior notes in October 2012 and the issuance of $600 million senior notes in April 2013; offset by

• a reduction of $10 million for the Parent Company primarily related to a $1.1 billion principal paydown in April 2013 on the Parent Company’s $2 billion term loan.

Interest expense for the six months ended June 30, 2013 increased primarily due to the following:

• interest expense related to Sunoco Logistics and Sunoco of $53 million;

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

• an increase of $21 million related to Regency primarily due to its issuance of $700 million senior notes in October 2012 and the issuance of $600 million senior notes in April 2013; and

• an increase of $11 million for the Parent Company primarily related to ETE’s senior secured term loan issued on March 26, 2012; offset by

• a reduction of several series of ETP’s higher coupon notes that were repurchased in the tender offers completed in January 2012.

Bridge Loan Related Fees. The bridge loan commitment fee recognized during the six months ended June 30, 2012 was incurred in connection with the Southern Union Merger. The Parent Company obtained permanent financing for the transaction through a $2 billion senior secured term loan which was funded upon closing of the Southern Union Merger on March 26, 2012.

Gain on Deconsolidation of Propane Business. ETP recognized a gain on deconsolidation related to the contribution of its Propane Business to AmeriGas in January 2012.

Gains on Interest Rate Derivatives. Gains on interest rate derivatives during the three and six months ended June 30, 2013 resulted from increases in forward interest rates, which caused our forward-starting swaps to increase in value. These swaps are marked to fair value for accounting purposes with changes in value recorded in earnings each period. Conversely, decreases in forward interest rates resulted in losses on interest rate derivatives during the three and six months ended June 30, 2012.

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.

Loss on Extinguishment of Debt. ETP recognized a loss on extinguishment of debt in connection with its repurchase of $750 million of senior notes in January 2012. In addition, Regency recognized a $7 million loss on extinguishment of debt in connection with its repurchase senior notes in June 2013 and $8 million in connection with its repurchase of senior notes in May 2012.

LIFO Valuation Adjustment. A LIFO valuation reserve adjustment was recorded 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 and MEP, as well as Citrus beginning March 26, 2012. The 2013 amounts also include our proportionate share of PES.

Adjusted EBITDA Related to Discontinued Operations. Amounts reflect the operations of Canyon, which was sold in October 2012, and Southern Union’s distribution operations beginning March 26, 2012.

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

Income Tax Expense. Income tax expense increased primarily due to the acquisitions of Southern Union and Sunoco, both of which are taxable corporations.

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of ETE has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impacts of the Propane Transaction, the Sunoco Merger and the Holdco Transaction for the six months ended June 30, 2012, giving effect that each occurred on January 1, 2012. This unaudited pro forma financial

43

information is provided to supplement the discussion and analysis of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Propane Transaction, the Sunoco Merger and the Holdco Transaction had been consummated on January 1, 2012.

The following table presents the pro forma financial information for the six months ended June 30, 2012:

	ETE Historical			Propane Transaction			(a)	Sunoco Historical			(b)	Southern Union Historical			(c)	Holdco Pro Forma Adjustments			(d)	Pro Forma
REVENUES	$	3,547		$	(93	)		$	24,435			$	443			$	(9,224	)		$	19,108
COSTS AND EXPENSES:
Cost of products sold and natural gas operations	2,383			(80		)		22,972				313				(8,545		)		17,043
Depreciation and amortization	360			(4		)		112				49				48				565
Selling, general and administrative	255			(1		)		309				—				(55		)		508
Impairment charges	—			—				108				—				(8		)		100
Total costs and expenses	2,998			(85		)		23,501				362				(8,560		)		18,216
OPERATING INCOME	549			(8		)		934				81				(664		)		892
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(557		)	2				(86		)		(50		)		(16		)		(707		)
Equity in earnings of affiliates	97			3				6				16				10				132
Gain on deconsolidation of Propane Business	1,057			(1,057		)		—				—				—				—
Gain (loss) on disposal of assets	—			2				104				—				7				113
Loss on extinguishment of debt	(123		)	115				—				—				—				(8		)
Gains on interest rate derivatives	(17		)	—				—				—				—				(17		)
Other, net	31			1				5				(2		)		—				35
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	1,037			(942		)		963				45				(663		)		440
Income tax expense	7			—				333				12				(306		)		46
INCOME FROM CONTINUING OPERATIONS	$	1,030		$	(942	)		$	630			$	33			$	(357	)		$	394

(a) Propane Transaction adjustments reflect the following:

• The adjustments reflect the deconsolidation of ETP’s propane operations in connection with the Propane Transaction.

• The adjustments reflect the pro forma impacts from the consideration received in connection with the Propane Transaction, including ETP’s receipt of AmeriGas common units and ETP’s use of cash proceeds from the transaction to redeem long-term debt.

• The 2012 adjustments include the elimination of (i) the gain recognized by ETP in connection with the deconsolidation of the Propane Business and (ii) ETP’s loss on extinguishment of debt recognized in connection with the use of proceeds to redeem long-term debt.

(b) Sunoco historical amounts in 2012 include the period from January 1, 2012 through March 31, 2012.

(c) Southern Union historical amounts in 2012 include the period from January 1, 2012 through March 25, 2012.

(d) Substantially all of the Holdco pro forma adjustments relate to Sunoco’s exit from its Northeast refining operations and formation of the PES joint venture, except for the following:

• The adjustment to depreciation and amortization reflects incremental amounts for estimated fair values recorded in purchase accounting related to Sunoco and Southern Union.

• The adjustment to selling, general and administrative expenses includes the elimination of merger-related costs incurred, because such costs would not have a continuing impact on results of operations.

44

• The adjustment to interest expense includes incremental amortization of fair value adjustments to debt recorded in purchase accounting.

• The adjustment to equity in earnings of affiliates reflects the reversal of amounts related to Citrus Corp. recorded in Southern Union’s historical income statements.

• The adjustment to income tax expense includes the pro forma impact resulting from the pro forma adjustments to pre-tax income of Sunoco and Southern Union.

Segment Operating Results

Investment in ETP

	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Revenues	$	11,551		$	1,596		$	9,955		$	22,405		$	2,919		$	19,486
Cost of products sold	10,229			799			9,430			19,823			1,580			18,243
Gross margin	1,322			797			525			2,582			1,339			1,243
Unrealized losses (gains) on commodity risk management activities	(18		)	(15		)	(3		)	(37		)	71			(108		)
Operating expenses, excluding non-cash compensation expense	(316		)	(189		)	(127		)	(624		)	(320		)	(304		)
Selling, general and administrative, excluding non-cash compensation expense	(115		)	(75		)	(40		)	(263		)	(184		)	(79		)
LIFO valuation adjustment	22			—			22			(16		)	—			(16		)
Adjusted EBITDA related to unconsolidated affiliates	158			97			61			323			196			127
Adjusted EBITDA related to discontinued operations	23			27			(4		)	63			34			29
Other	(5		)	(4		)	(1		)	6			5			1
Elimination	(2		)	4			(6		)	(9		)	(5		)	(4		)
Segment Adjusted EBITDA	$	1,069		$	642		$	427		$	2,025		$	1,136		$	889

Gross Margin. For the three and six months ended June 30, 2013 compared to the same periods last year, gross margin increased $525 million and $1.24 billion, respectively, primarily as a result of ETP’s acquisition of Sunoco, including Sunoco Logistics and retail marketing operations, in conjunction with the Holdco Transaction in October 2012. Sunoco Logistics’ gross margin was $288 million and $576 million for the three and six months ended June 30, 2013, respectively, and retail marketing gross margin was $204 million and $390 million for the three and six months ended June 30, 2013, respectively. In addition, NGL transportation and services gross margin increased $34 million and $73 million for the three and six months ended June 30, 2013, respectively, primarily as a result of increased volumes transported.

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 on inventory. The increase in unrealized gains on commodity risk management activities for the six months ended June 30, 2013 compared to 2012 was primarily attributable to natural gas storage inventory and related derivatives.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and six months ended June 30, 2013 compared to the same periods last year, ETP’s operating expense increases of $25 million and $51 million, respectively, were attributable to Sunoco Logistics, and $106 million and $204 million, respectively, were attributable to ETP’s retail marketing operations. As discussed above, Sunoco Logistics and the retail marketing operations were acquired in October of 2012. In addition, operating expenses increased in ETP’s NGL transportation and midstream operations as a result of assets recently being placed in service.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three and six months ended June 30, 2013 compared to the same periods last year, ETP’s selling, general and administrative increases of $29 million and $59 million, respectively, were attributable to Sunoco Logistics, and $23 million and $38 million, respectively, were attributable to ETP’s retail marketing operations. As discussed above, Sunoco Logistics and the retail marketing operations were acquired in October of

45

2012. Selling, general and administrative attributable to ETP’s interstate operations decreased $5 million and $23 million for the three and six months ended June 30, 2013 compared to the same periods in 2012 primarily as a result of decreased employee-related expenses.

Adjusted EBITDA Related to Unconsolidated Affiliates. Adjusted EBITDA related to unconsolidated affiliates for the three and six months ended June 30, 2013 consisted of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013		2012		Change		2013		2012		Change
AmeriGas	$	16	$	—	$	16	$	113	$	75	$	38
Citrus	79		77		2		141		81		60
FEP	19		18		1		37		37		—
Other	28		2		26		16		3		13
Total Adjusted EBITDA related to unconsolidated affiliates	$	142	$	97	$	45	$	307	$	196	$	111

Adjusted EBITDA Related to Discontinued Operations. Amounts reflected the operations of Canyon, which was sold in October 2012, and Southern Union’s distribution operations beginning March 26, 2012.

Investment in Regency

	Three Months Ended June 30,									Six Months Ended June 30,
	2013			2012			Change			2013			2012			Change
Revenues	$	639		$	511		$	128		$	1,179		$	886		$	293
Cost of products sold	445			336			109			832			590			242
Gross margin	194			175			19			347			296			51
Unrealized losses (gains) on commodity risk management activities	(4		)	(21		)	17			14			(24		)	38
Operating expenses, excluding non-cash compensation expense	(73		)	(57		)	(16		)	(142		)	(98		)	(44		)
Selling, general and administrative, excluding non-cash compensation expense	(17		)	(24		)	7			(48		)	(55		)	7
Adjusted EBITDA related to unconsolidated affiliates	60			59			1			123			116			7
Other	(7		)	5			(12		)	(20		)	22			(42		)
Segment Adjusted EBITDA	$	153		$	137		$	16		$	274		$	257		$	17

Gross Margin. Regency’s gross margin increased for the three and six months ended June 30, 2013 compared to the same periods last year primarily as a result of increased volumes in south and west Texas in Regency’s gathering and processing operations. In addition, because the SUGS Contribution was a transaction between entities under common control, Regency has retrospectively consolidated SUGS beginning March 26, 2012. As such, the six months ended June 30, 2013 included a full period of SUGS results, while the six months ended June 30, 2012 included a partial period of SUGS results.

Unrealized Losses (Gains) on Commodity Risk Management Activities. Regency's losses on commodity risk management activities increased primarily due to mark-to-market adjustments on its non-hedged commodity derivatives.

Operating Expenses, Excluding Non-Cash Compensation Expense. Regency's operating expenses increased for the three and six months ended June 30, 2013 compared to the same periods last year primarily as a result of increased plant and pipeline maintenance and materials and employee expenses from increased operating activity in South and West Texas. In addition, activity related to SUGS was included beginning March 26, 2012, and as such, the six months ended June 30, 2012 included a partial period of SUGS’ operating expenses.

46

Selling, General and Administrative. Regency's operating expenses decreased for the three and six months ended June 30, 2013 compared to the same periods last year primarily as a result of a decrease in employee expenses and a decrease in the management fee paid to ETE. In connection with the SUGS Acquisition, ETE agreed to suspend a $10 million management fee paid annually by Regency to ETE for two years after the transaction close.

Adjusted EBITDA Related to Unconsolidated Affiliates. Regency's adjusted EBITDA attributable to unconsolidated affiliates increased primarily due to an $11 million increase in adjusted EBITDA attributable to Lone Star, which was partially offset by a $6 million decrease in Regency’s interest in adjusted EBITDA attributable to HPC.

Other. Regency’s other decreased primarily as a result of unrealized losses recorded related to the embedded derivative in Regency’s Preferred Units. Additionally, Regency's other decreased as the result of recognition of a $16 million one-time producer payment received in March 2012 related to an assignment of certain contracts.

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. 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 and Regency. 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.

47

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 for the full year 2013 to be within the following ranges:

	Growth						Maintenance
	Low			High			Low		High
ETP legacy assets:
Intrastate transportation and storage	$	10		$	10		$	20	$	25
Interstate transportation and storage	15			20			25		30
Midstream	360			380			45		50
NGL transportation and services(1)	445			465			15		20
	830			875			105		125
Holdco:
Southern Union transportation and storage	20			30			75		80
Southern Union gathering and processing	95			95			10		10
Retail marketing	50			70			70		85
	165			195			155		175
Investment in Sunoco Logistics	685			710			60		65
All other (including eliminations)	(10		)	(10		)	40		70
Total projected capital expenditures	$	1,670		$	1,770		$	360	$	435

⁽¹⁾  ETP expects to receive capital contributions from Regency related to their 30% share of Lone Star of $60 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. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETP experiences increases in pipe costs due to a number of reasons, including but not limited to, 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 2013; 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 metrics or other partnership purposes.

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 2013, Regency expects to invest $800 million in growth capital expenditures, of which $465 million is expected to be invested in organic growth projects in the gathering and processing operations; $175 million is expected to be invested in Regency’s portion of growth capital expenditures in its NGL services segment; and $160 million is expected to be invested in growth capital expenditures in its contract services segment. In addition, Regency expects to invest $45 million in maintenance capital expenditures in 2013, 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.

48

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.

Six months ended June 30, 2013 compared to six months ended June 30, 2012. Cash provided by operating activities during 2013 was $1.13 billion as compared to $425 million for 2012. Net income was $660 million and $1.04 billion for 2013 and 2012, respectively. The difference between net income and the net cash provided by operating activities primarily consisted of non-cash items totaling $569 million and $559 million and changes in operating assets and liabilities of $293 million and $153 million for 2013 and 2012, respectively.

The non-cash activity in 2013 consisted primarily of depreciation and amortization of $630 million compared to $360 million in 2012. The non-cash activity in 2012 consisted primarily of the gain on deconsolidation of Propane Business of $1.06 billion, the loss on extinguishment of debt of $123 million, and bridge loan related fees of $62 million which were not reflected in 2013.

Cash paid for interest, net of interest capitalized, was $608 million and $416 million for the six months endedJune 30, 2013 and 2012, respectively.

Capitalized interest for the six months endedJune 30, 2013 was $18 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 the contribution of ETP’s Propane Business. Changes in capital expenditures between periods primarily result from increases or decreases in growth capital expenditures to fund construction and expansion projects.

Six months ended June 30, 2013 compared to six months ended June 30, 2012. Cash used in investing activities during 2013 was $1.43 billion as compared to $2.73 billion for 2012. In 2012, we paid cash for acquisitions of $2.98 billion, which primarily consisted of our acquisition of Southern Union for $2.97 billion. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2013 were $1.50 billion, including changes in accruals of $42 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2012 of $1.29 billion, including changes in accruals of $271 million. In 2012, ETP also received cash proceeds from its contribution and sale of propane operations of $1.44 billion.

Financing Activities

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

Six months ended June 30, 2013 compared to six months ended June 30, 2012. Cash provided by financing activities during 2013 was $556 million as compared to $2.40 billion for 2012. In 2013, ETP received $1.09 billion in net proceeds from offerings of ETP Common Units as compared to $94 million in 2012. In 2013, Regency received $128 million in net proceeds from offerings of Regency Common Units as compared to $297 million in 2012. During 2013, we had a consolidated net increase in our debt

49

level of $758 million as compared to a net increase of $2.86 billion for 2012. We paid distributions of $360 million and $315 million to our partners in 2013 and in 2012, respectively. Our subsidiaries paid distributions to noncontrolling interest of $684 million and $447 million in 2013 and 2012, respectively. In 2013, we also paid $340 million to redeem our Preferred Units.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

	June 30, 2013			December 31, 2012
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020	$	1,800		$	1,800
ETE Senior Secured Term Loan, due March 26, 2017	900			2,000
ETE Senior Secured Revolving Credit Facility	—			60
Subsidiary Indebtedness:
ETP	10,032			7,692
Transwestern	870			870
Regency	2,400			1,962
Southern Union	170			1,260
Panhandle	1,621			1,621
Sunoco	965			965
Sunoco Logistics	2,150			1,450
Revolving Credit Facilities	1,470			1,936
Other Long-Term Debt	49			48
Unamortized premiums and fair value adjustments, net	332			389
Total	22,759			22,053
Current maturities	(899		)	(613		)
Long-term debt and notes payable, less current maturities	$	21,860		$	21,440

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, 2012, filed with the SEC on March 1, 2013 and in Note 8 to our consolidated financial statements. As a result of the Southern Union Merger, we incurred additional indebtedness which is summarized below.

Credit Facilities

Parent Company Credit Facility

The Parent Company has a $200 million revolving credit facility that expires in September 2015. Indebtedness under the Parent Company 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 June 30, 2013, we had no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.

ETP Credit Facility

ETP has a $2.5 billion revolving credit facility, the ETP Credit Facility, that expires in October 2016. 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 ETP’s current and future unsecured debt.

As of June 30, 2013, ETP had $900 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.49 billion after taking into account letters of credit of $107 million. The weighted average interest rate on the total amount outstanding as of June 30, 2013 was 1.70%.

Regency Credit Facility

As of June 30, 2013, there was a balance outstanding under the Regency Credit Facility of $535 million in revolving credit loans and approximately $13 million in letters of credit. The total amount available under the Regency Credit Facility, as of June 30,

50

2013, which was reduced by any letters of credit, was approximately $652 million, and the weighted average interest rate on the total amount outstanding as of June 30, 2013 was 2.20%.

Southern Union Credit Facilities

Proceeds from the SUGS Contribution were used to repay $240 million of borrowings under the Southern Union Credit Facility and the facility was terminated.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains two credit facilities to fund its working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 and a $200 million unsecured credit facility which expires in August 2013. There were no outstanding borrowings under these facilities as of June 30, 2013.

West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility. Outstanding borrowings under this credit facility were $35 million as of June 30, 2013.

Covenants Related to Our Credit Agreements

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of June 30, 2013.

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, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 19, 2013	$	0.635
March 31, 2013	May 6, 2013	May 17, 2013	0.645
June 30, 2013	August 5, 2013	August 19, 2013	0.655

The total amounts of distributions declared and/or paid during the six months endedJune 30, 2013 and 2012 were as follows (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):

	Six Months Ended June 30,
	2013		2012
Limited Partners	$	365	$	350
General Partner interest	1		1
Total Parent Company distributions	$	366	$	351

51

Cash Distributions Received from Subsidiaries

In addition to the cash flows generated through its wholly-owned subsidiary, Southern Union, the Parent Company’s principal sources of cash flow includes the distributions that it receives from its direct and indirect investments in ETP and Regency. The total amount of distributions the Parent Company received or will receive from ETP and Regency relating to our limited partner interests, general partner interest and IDRs (shown in the period to which they relate) for the periods ended as noted below is as follows:

	Six Months Ended June 30,
	2013			2012
Distributions from ETP:
Limited Partners (1)	$	178		$	90
General Partner interest	10			10
IDRs	363			234
IDR relinquishments related to previous transactions (2)	(86		)	(28		)
Total distributions from ETP (3)	465			306
Distributions from Regency:
Limited Partners	24			24
General Partner interest	2			3
IDRs	5			4
IDR relinquishment related to previous transaction (4)	(1		)	—
Total distributions from Regency	30			31
Total distributions received from subsidiaries	$	495		$	337

⁽¹⁾  Does not include common unit distributions received by Southern Union in respect of approximately 2,249,092 ETP Common Units issued to Southern Union in connection with the Citrus Merger.

⁽²⁾  Following are incentive distributions ETE has agreed to relinquish to ETP:

• In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of the incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.

• In conjunction with the Holdco transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.

• As discussed in Note 2, in connection with ETP’s acquisition of ETE’s 60% interest in Holdco on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.

As discussed in Note 10 to our consolidated financial statements, ETP has agreed to make incremental cash distributions of $329 million over 15 quarters, commencing with the quarter ending September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition.

As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:

	Quarters Ending
	March 31		June 30		September 30		December 31		Total Year
2013	N/A		N/A		$	21.00	$	21.00	$	42.00
2014	$	27.25	$	27.25	27.25		27.25		109.00
2015	13.25		13.25		13.25		13.25		53.00
2016	5.50		5.50		5.50		5.50		22.00

52

⁽³⁾  Total distributions received from ETP does not include distributions on ETP’s Class E Units or Class F Units, which are held by subsidiaries of Holdco, which is 60% owned by ETE subsequent to October 5, 2012, and 100% owned by ETP subsequent to April 30, 2013.

⁽⁴⁾  In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego incentive distributions with respect to the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

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, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.89375
March 31, 2013	May 6, 2013	May 15, 2013	0.89375
June 30, 2013	August 5, 2013	August 14, 2013	0.89375

The total amounts of ETP distributions declared during the six months endedJune 30, 2013 and 2012 were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):

	Six Months Ended June 30,
	2013			2012
Limited Partners	$	665		$	425
General Partner interest	10			10
IDRs	363			234
IDR relinquishments related to previous transactions	(86		)	(28		)
Total ETP distributions	$	952		$	641

The distributions reflected above for the six months ended June 30,2013 reflect IDR reductions totaling $86 million, which includes two quarters of IDR relinquishment related to the Citrus Merger, two quarters of IDR relinquishment related to the Holdco Transaction and one quarter of IDR relinquishment related to the Holdco Acquisition. The distributions reflected above for the six months ended June 30,2012 reflect IDR reductions totaling $28 million, which includes two quarters of IDR relinquishment related to the Citrus Merger.

Cash Distributions Paid by Regency

Following are distributions declared and/or paid by Regency subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.460
March 31, 2013	May 6, 2013	May 13, 2013	0.460
June 30, 2013	August 5, 2013	August 14, 2013	0.465

The total amounts of Regency distributions declared and/or paid during the six months endedJune 30, 2013 and 2012 were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

53

	Six Months Ended June 30,
	2013			2012
Limited Partners	$	174		$	156
General Partner interest	2			3
IDRs	5			4
IDR relinquishment related to previous transaction	(1		)	—
Total Regency distributions	$	181		$	163

Cash Distributions Paid by Sunoco Logistics

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 8, 2013	February 14, 2013	$	0.5450
March 31, 2013	May 9, 2013	May 15, 2013	0.5725
June 30, 2013	August 8, 2013	August 14, 2013	0.6000

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

	Six Months Ended June 30, 2013
Limited Partners:
Common Units	$	121
General Partner interest	2
IDRs	53
Total Sunoco Logistics distributions	$	176

Sunoco Logistics declared $94 million in cash distributions to ETP for the six months ended June 30, 2013.

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, 2012 filed with the SEC on March 1, 2013.

54

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, 2012, 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, 2012. There have been no material changes to our primary market risk exposures or how those exposures are managed since December 31, 2012.

Commodity Price Risk

The tables below summarize by operating entity commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of June 30, 2013 and December 31, 2012.

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.

55

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.

	June 30, 2013							December 31, 2012
	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			(in millions)							(in millions)
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	9,650,000		$	(3	)	$	—	—		$	—		$	—
Basis Swaps IFERC/NYMEX (1)	(37,702,500	)	(3		)	4		(30,980,000	)	(6		)	—
Power (Megawatt):
Forwards	145,078		—			1		19,650		—			1
Futures	(557,260	)	—			1		(1,509,300	)	(1		)	1
Options — Calls	(1,200	)	3			1		1,656,400		2			1
Crude (Bbls) — Futures	(80,000	)	—			1		—		—			—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	8,770,000		(1		)	—		150,000		(1		)	—
Swing Swaps IFERC	20,060,000		(1		)	—		(83,292,500	)	1			1
Fixed Swaps/Futures	23,435,000		1			16		27,077,500		(7		)	9
Forward Physical Contracts	1,758,402		1			—		11,689,855		—			2
NGLs (Bbls) — Forwards/Swaps	(597,000	)	2			1		(30,000	)	—			—
Refined Products (Bbls) — Futures	(1,227,000	)	1			14		(666,000	)	(3		)	14
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(10,530,000	)	—			—		(18,655,000	)	(1		)	—
Fixed Swaps/Futures	(32,682,500	)	12			13		(44,272,500	)	4			15
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(2,300,000	)	—			—		—		—			—
Fixed Swaps/Futures	(4,140,000	)	1			2		(8,212,500	)	(3		)	3
NGLs (Bbls) — Forwards/Swaps	(690,000	)	6			4		(930,000	)	(2		)	7
Refined Products (Bbls) — Futures	—		—			—		(98,000	)	—			1
Crude (Bbls) — Futures	(210,000	)	(1		)	2		—		—			—

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

56

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.

	June 30, 2013					December 31, 2012
	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:
Fixed Swaps/Futures	18,672,000	$	7	$	7	8,395,000	$	1	$	3
Propane:
Forwards/Swaps	20,496,000	2		2		3,318,000	1		1
NGLs:
Forwards/Swaps	234,000	2		1		243,000	—		2
WTI Crude Oil:
Forwards/Swaps	700,000	1		7		356,000	2		3

Interest Rate Risk

As of June 30, 2013, we and our subsidiaries had $3.43 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $34 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 June 30, 2013 and December 31, 2012 (dollars in millions), none of which are designated as hedges for accounting purposes:

			Notional Amount Outstanding
Entity	Term	Type(1)	June 30, 2013		December 31, 2012
ETE	March 2017	Pay a fixed rate of 1.25% and receive a floating rate	$	500	$	500
ETP	July 2013 (2)	Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	100		400
ETP	July 2014 (2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	400		400
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	600		600
ETP	February 2023	Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%	400		—
Southern Union	November 2016	Pay a fixed rate of 2.91% and receive a floating rate	75		75
Southern Union	November 2021	Pay a fixed rate of 3.75% and receive a floating rate	450		450

⁽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.

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 $42 million as of June 30, 2013 and $118 million as of December 31, 2012. For the $1 billion 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 $10 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect

57

cash flows until the swaps are settled. For Southern Union’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 $5 million.

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposures associated with a single or multiple counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry including petrochemical companies, consumer and industrials, oil and gas producers, municipalities, utilities and midstream companies. Our overall exposure to credit risk may be affected either positively or negatively in that the counterparties may experience similar changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

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.

Certain of Southern Union’s derivative instruments contain provisions that require Southern Union’s debt to be maintained at an investment grade credit rating from each of the major credit rating agencies. If Southern Union’s debt were to fall below investment grade, Southern Union would be in violation of these provisions, and the counterparties to the derivative instruments could potentially require Southern Union to post collateral for certain of the derivative instruments.

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 sheet and recognized in net income or other comprehensive income.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Under the supervision and with the participation of senior management, including the President (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of June 30, 2013 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

58

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2012 and Note 14 – 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 June 30, 2013.

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, 2012.

59

ITEM 6. EXHIBITS

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

	Exhibit Number	Description
(*)	3.1	Amendment No. 4, dated April 30, 2013, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended.
(*)	4.1	Registration Rights Agreement, dated April 30, 2013, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P.
(*)	10.1	First Amendment, dated April 30, 2013, to the Services Agreement, effective as of May 26, 2010, by and among Energy Transfer Equity, L.P., ETE Services Company LLC and Regency Energy Partners LP.
(*)	10.2	Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.
(*)	10.3	Amendment No. 2 to Senior Secured Term Loan Agreement by and among Energy Transfer Equity, L.P., the Restricted Persons party thereto, the Lenders party thereto and Credit Suisse AG, in its capacity as administrative agent for the Lenders dated as of April 25, 2012.
(*)	10.4	Amendment No. 1 to Senior Secured Bridge Term Loan Agreement by and among Energy Transfer Equity, L.P., the Restricted Persons party thereto, the Lenders party thereto and Credit Suisse AG, in its capacity as administrative agent for the Lenders dated as of April 25, 2012.
(*)	10.5	Amendment No. 2 to Amended and Restated Credit Agreement by and among Energy Transfer Equity, L.P., the Restricted Persons party thereto, the Lenders party thereto and Credit Suisse AG, in its capacity as administrative agent for the Lenders dated as of April 29, 2012.
	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 May 1, 2013.
**	Furnished herewith.

60

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, L.L.C., its General Partner
Date:	August 8, 2013	By:	/s/ Jamie Welch
			Jamie Welch
			Chief Financial Officer (duly authorized to sign on behalf of the registrant)

61

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

AND CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: August 8, 2013

/s/ John W. McReynolds

John W. McReynolds

President

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

AND 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: August 8, 2013

/s/ Jamie Welch

Jamie Welch

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2013, 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: August 8, 2013

/s/ John W. McReynolds

John W. McReynolds

President

* A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Energy Transfer Equity, L.P.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2013, 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: August 8, 2013

/s/ Jamie Welch

Jamie Welch

Chief Financial Officer

* A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Energy Transfer Equity, L.P.

XML

Reportable Segments (Assets Segments)(Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Assets	$ 50,143	$ 48,904
Investment In ETP [Member]
Assets	43,651	43,320
Investment In Regency [Member]
Assets	8,521	8,123
Corporate And Other [Member]
Assets	704	707
Adjustments And Eliminations [Member]
Assets	$ (2,733)	$ (3,246)

XML

Reportable Segments Revenues from External Customers by Segment (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Segment Reporting Information [Line Items]
Revenues	$ 12,063	$ 1,877	$ 23,242	$ 3,547
Intrastate Transportation And Storage [Member]
Segment Reporting Information [Line Items]
Revenue from External Customers	558	452	1,209	899
Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Revenue from External Customers	354	310	677	452
Midstream [Member]
Segment Reporting Information [Line Items]
Revenue from External Customers	588	629	1,338	1,088
NGL Transportation And Services [Member] [Member]
Segment Reporting Information [Line Items]
Revenue from External Customers	420	148	766	302
Sunoco Logistics [Member]
Segment Reporting Information [Line Items]
Revenue from External Customers	4,256	0	7,713	0
Retail Marketing [Member]
Segment Reporting Information [Line Items]
Revenue from External Customers	5,291	0	10,508	0
All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue from External Customers	84	57	194	178
Gathering And Processing [Member]
Segment Reporting Information [Line Items]
Revenues	583	462	1,069	787
Contract Services [Member]
Segment Reporting Information [Line Items]
Revenues	52	44	101	90
Corporate And Others [Member]
Segment Reporting Information [Line Items]
Revenues	4	5	9	9
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Revenues	11,551	1,596	22,405	2,919
Less: Intersegment revenues	22	12	39	16
Revenue from External Customers	11,529	1,584	22,366	2,903
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Revenues	639	511	1,179	886
Less: Intersegment revenues	11	2	16	6
Revenue from External Customers	$ 628	$ 509	$ 1,163	$ 880

XML

Unit-Based Compensation Plans

6 Months Ended

Jun. 30, 2013

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Unit-Based Compensation Plans

UNIT-BASED COMPENSATION PLANS:

We and certain of our subsidiaries have equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase common units, restricted units, phantom units, DERs, common unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

During the six months ended June 30, 2013, 750,000 awards were granted to an ETE employee and 6,042 awards were granted to ETE directors. As of June 30, 2013 a total of 804,190 unit awards remain unvested. We expect to recognize a total of $42 million in compensation expense over a weighted average period of 4.5 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the six months ended June 30, 2013, ETP employees were granted a total of 1,074,163 unvested awards with five-year service vesting requirements, and directors were granted a total of 9,060 unvested awards with three-year and five-year service vesting requirements. The weighted average grant-date fair value of these awards was $45.37 per unit. As of June 30, 2013 a total of 2,827,915 unit awards remain unvested, including the new awards granted during the period. ETP expects to recognize $76 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.

Regency Unit-Based Compensation Plans

During the six months ended June 30, 2013, Regency employees and directors were granted 52,360 Regency phantom units with 5-year service vesting requirements. As of June 30, 2013, a total of 1,189,247 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.43 per unit. Regency expects to recognize a total of $22 million in compensation expense over a period of 5 years related to Regency’s unvested phantom units.

Sunoco Logistics Unit-Based Compensation Plan

As of June 30, 2013, a total of 936,438 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $19 million in compensation expense over a weighted-average period of 2.5 years.

XML

Debt Obligations (Southern Union Credit Facility) (Narrative) (Details) (Southern Union Credit Facility [Member], USD $) In Millions, unless otherwise specified	Apr. 30, 2013
Southern Union Credit Facility [Member]
Line of Credit Facility [Line Items]
Amount Outstanding	$ 240

XML

Consolidated Statements Of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Statement of Other Comprehensive Income [Abstract]
Net income	$ 338	$ 75	$ 660	$ 1,036
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	(1)	(8)	(2)	(8)
Change in value of derivative instruments accounted for as cash flow hedges	6	(1)	8	21
Change in value of available-for-sale securities	(1)	0	0	0
Actuarial loss relating to pension and other postretirement benefits	2	0	1	0
Foreign currency translation adjustment	0	0	(1)	0
Change in other comprehensive income from equity investments	(3)	(22)	4	(22)
Other comprehensive income (loss), net of tax	3	(31)	10	(9)
Comprehensive income	341	44	670	1,027
Less: Comprehensive income attributable to noncontrolling interest	209	(4)	447	806
Comprehensive income attributable to partners	$ 132	$ 48	$ 223	$ 221

XML

Cash And Cash Equivalents

6 Months Ended

Jun. 30, 2013

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 are as follows:

	Six Months Ended June 30,
	2013			2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	538		$	485
Accrued advances to affiliates	$	—		$	4
Net losses from subsidiary common unit transactions	$	(364	)	$	(14	)
AmeriGas limited partner interest received in Propane Contribution	$	—		$	1,123
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger	$	—		$	2,354
Subsidiary issuances of common units in connection with certain acquisitions	$	—		$	112

XML

Reportable Segments

6 Months Ended

Jun. 30, 2013

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

As a result of the Holdco Acquisition in April 2013, 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; 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 previously reported net income as a measure of segment performance. Due to the change in our reportable segments described above, the financial information available to our chief operating decision maker to assess the performance is now based on Segment Adjusted EBITDA. Therefore, we have accordingly revised our segment operating performance measure that we report. 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 includes 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 segment performance measure, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

As discussed in Note 2, 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 reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.

• ETP’s Segment Adjusted ABITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Because 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 include the results of SUGS from March 26, 2012 to April 30, 2013.

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Segment Adjusted EBITDA:
Investment in ETP	$	1,069		$	642		$	2,025		$	1,136
Investment in Regency	153			137			274			257
Corporate and Other	(23		)	(10		)	(29		)	(41		)
Adjustments and Eliminations	(36		)	(41		)	(55		)	(43		)
Total	1,163			728			2,215			1,309
Depreciation and amortization	(318		)	(206		)	(630		)	(360		)
Interest expense, net of interest capitalized	(305		)	(282		)	(615		)	(495		)
Bridge loan related fees	—			—			—			(62		)
Gain on deconsolidation of Propane Business	—			1			—			1,057
Gains (losses) on interest rate derivatives	46			(44		)	52			(17		)
Non-cash unit-based compensation expense	(11		)	(12		)	(27		)	(24		)
Unrealized gains (losses) on commodity risk management activities	22			37			23			(47		)
Losses on extinguishment of debt	(7		)	(8		)	(7		)	(123		)
Gain on curtailment of other postretirement benefit plans	—			—			—			15
LIFO valuation adjustment	(22		)	—			16			—
Equity in earnings of unconsolidated affiliates	54			22			144			97
Adjusted EBITDA related to unconsolidated affiliates	(184		)	(140		)	(388		)	(281		)
Adjusted EBITDA related to discontinued operations	(23		)	(27		)	(63		)	(34		)
Other, net	3			4			(4		)	2
Income from continuing operations before income tax expense	$	418		$	73		$	716		$	1,037

	June 30, 2013			December 31, 2012
Total assets:
Investment in ETP	$	43,651		$	43,320
Investment in Regency	8,521			8,123
Corporate and Other	704			707
Adjustments and Eliminations	(2,733		)	(3,246		)
Total	$	50,143		$	48,904

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues:
Investment in ETP:
Revenues from external customers	$	11,529		$	1,584		$	22,366		$	2,903
Intersegment revenues	22			12			39			16
	11,551			1,596			22,405			2,919
Investment in Regency:
Revenues from external customers	628			509			1,163			880
Intersegment revenues	11			2			16			6
	639			511			1,179			886
Corporate and Other:
Revenues from external customers	—			4			—			2
Adjustments and Eliminations	(127		)	(234		)	(342		)	(260		)
Total revenues	$	12,063		$	1,877		$	23,242		$	3,547

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

Investment in ETP

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Intrastate Transportation and Storage	$	558	$	452	$	1,209	$	899
Interstate Transportation and Storage	354		310		677		452
Midstream	588		629		1,338		1,088
NGL Transportation and Services	420		148		766		302
Investment in Sunoco Logistics	4,256		—		7,713		—
Retail Marketing	5,291		—		10,508		—
All Other	84		57		194		178
Total revenues	11,551		1,596		22,405		2,919
Less: Intersegment revenues	22		12		39		16
Revenues from external customers	$	11,529	$	1,584	$	22,366	$	2,903

Investment in Regency

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Gathering and Processing	$	583	$	462	$	1,069	$	787
Contract Services	52		44		101		90
Corporate and others	4		5		9		9
Total revenues	639		511		1,179		886
Less: Intersegment revenues	11		2		16		6
Revenues from external customers	$	628	$	509	$	1,163	$	880

XML

Price Risk Management Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)	Jun. 30, 2013 MMbtu	Dec. 31, 2012 MMbtu
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(37,702,500)	(30,980,000)
Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	9,650,000
Trading [Member] | Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(80,000)
Maximum Term Of Commodity Derivatives	2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(557,260)	(1,509,300)
Maximum Term Of Commodity Derivatives	2013	2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | Call Option [Member] | ETP [Member]
Notional Volume	(1,200)	1,656,400
Maximum Term Of Commodity Derivatives	2013	2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	145,078	19,650
Maximum Term Of Commodity Derivatives	2013	2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [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] | Maximum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015
Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2013	2013
Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	(1,227,000)	(666,000)
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	8,770,000	150,000
Maximum Term Of Commodity Derivatives		2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Swing Swaps IFERC (MMBtu) [Member] | ETP [Member]
Notional Volume	20,060,000	(83,292,500)
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	23,435,000	27,077,500
Maximum Term Of Commodity Derivatives		2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Notional Volume	18,672,000	8,395,000
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Swaps [Member] | ETP [Member]
Notional Volume	1,758,402	11,689,855
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	(597,000)	(30,000)
Maximum Term Of Commodity Derivatives		2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	234,000	243,000
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	700,000	356,000
Maximum Term Of Commodity Derivatives		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	20,496,000	3,318,000
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [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] | Maximum [Member] | Natural Gas [Member] | Forward Physical Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Natural Gas [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2015
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | NGL [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Forward Physical Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | NGL [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(10,530,000)	(18,655,000)
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(32,682,500)	(44,272,500)
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Fair Value Hedging [Member] | Natural Gas [Member] | Hedged Item - Inventory [Member] | ETP [Member]
Notional Volume	32,682,500	44,272,500
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Cash Flow Hedging [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume		(98,000)
Maximum Term Of Commodity Derivatives		2013
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(2,300,000)
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(4,140,000)	(8,212,500)
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Cash Flow Hedging [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	(690,000)	(930,000)
Maximum Term Of Commodity Derivatives	2013	2013
Non Trading [Member] | Cash Flow Hedging [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]
Notional Volume	(210,000)
Maximum Term Of Commodity Derivatives	2013

XML

Equity (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended			6 Months Ended		3 Months Ended		0 Months Ended	6 Months Ended	3 Months Ended	12 Months Ended			6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Mar. 31, 2013	Jun. 30, 2013 Goldman Sachs [Member]	Jun. 30, 2013 Distribution Reinvestment Plan [Member]	Dec. 31, 2013 ETE [Member]	Jun. 30, 2013 ETP [Member]	Aug. 07, 2013 Class H Units [Member]	Jun. 30, 2013 Class H Units [Member]	Sep. 30, 2013 Class H Units [Member] ETE [Member]	Dec. 31, 2016 Class H Units [Member] ETE [Member]	Dec. 31, 2015 Class H Units [Member] ETE [Member]	Dec. 31, 2014 Class H Units [Member] ETE [Member]	Jun. 30, 2013 Citrus Merger [Member] quarters	Jun. 30, 2013 Holdco Transaction [Member] quarters
Equity Distribution Reinvestment Program, Capacity, Shares							3,300,000
Gain on Sale of Previously Unissued Stock by Subsidiary	$ (364)	$ (14)
Equity Distribution Agreement, Capacity	800		200
Partners' Capital Account, Units, Sold in Public Offering	13,800,000
Proceeds from issuance of common units	657			26
Partners' Capital Account, Units, Redeemed								50,200,000
Allocation of Profits, Losses and Other by Sunoco, Percent								50.00%
Distributions by Sunoco, IDRs and General Partner Interest								50.00%
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement				387
Equity Distribution Agreement Commissions	4
Equity Distribution Reinvestment Program, Capacity, Shares							609
Number of periods of incentive distributions to be relinquished in future periods contingent upon closing of proposed transaction.														16	12
Relinquishment of Rights of Incentive Distributions														220	210
Price per Unit	$ 48.05
Class H Incremental Cash Distributions									329
Proceeds From Underwriter Agreement					46
Incentive Distributions						$ 21				$ 21	$ 22	$ 53	$ 109

XML

Income Taxes (Notes)

6 Months Ended

Jun. 30, 2013

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES:

The following table summarizes the Partnership’s income tax expense from continuing operations:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Income tax expense from continuing operations	$	89		$	5		$	87		$	7
Effective tax rate	21		%	7		%	12		%	1		%

The increase in the effective tax rate in the 2013 periods presented over the 2012 periods presented is primarily due to the Partnership conducting a significant portion of its activities through corporate subsidiaries, Southern Union and Sunoco. The Southern Union transaction was completed in March 2012 while the Holdco and Sunoco transactions were completed in October 2012.

XML

Net Income Per Limited Partner Unit (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Income from continuing operations	$ 329	$ 68	$ 629	$ 1,030
Income (Loss) from Continuing Operations Attributable to Noncontrolling Interest	206	19	428	815
Income from continuing operations, net of noncontrolling interest	123	49	201	215
Less: General Partner’s interest in income from continuing operations	0	0	0	1
Income from continuing operations available to Limited Partners	123	49	201	214
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average Limited Partner units	280.5	280.0	280.2	253.3
Basic income from continuing operations per Limited Partner unit	0.44	0.18	0.72	0.85
Basic income from discontinued operations per Limited Partner unit	$ 0.01	$ 0.01	$ 0.05	$ 0.02
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive effect of equity-based compensation of subsidiaries	0	0	0	(1)
Diluted net income available to Limited Partners	$ 123	$ 49	$ 201	$ 213
Weighted average Limited Partner units	280.5	280.0	280.2	253.3
Diluted income from continuing operations per Limited Partner unit	0.44	0.18	0.72	0.84
Diluted income from discontinued operations per Limited Partner unit	$ 0.01	$ 0.01	$ 0.05	$ 0.02

XML

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Cash and cash equivalents	$ 621	$ 372	$ 218	$ 126
Accounts receivable from related companies	82	71
Other current assets	285	311
Total current assets	6,153	5,597
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,640	4,737
INTANGIBLE ASSETS, net	2,221	2,291
GOODWILL	6,372	6,434
OTHER NON-CURRENT ASSETS, net	546	533
Total assets	50,143	48,904
Accounts payable	3,385	3,107
Accounts payable to related companies	14	15
Interest payable	323	334
Price risk management liabilities	57	115
Accrued and other current liabilities	1,542	1,754
Current maturities of long-term debt	899	613
Total current liabilities	6,125	5,845
LONG-TERM DEBT, less current maturities	21,860	21,440
PREFERRED UNITS OF SUBSIDIARY	73	73
OTHER NON-CURRENT LIABILITIES	849	995
COMMITMENTS AND CONTINGENCIES
General Partner	(2)	0
Limited Partners	1,485	2,125
Accumulated other comprehensive loss	(2)	(12)
Total partners’ capital	1,481	2,113
Total liabilities and equity	50,143	48,904
Parent Company [Member]
Cash and cash equivalents	72	9	3	18
Accounts receivable from related companies	8	11
Other current assets	1	3
Total current assets	81	23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,080	6,094
INTANGIBLE ASSETS, net	16	19
GOODWILL	9	9
Notes Receivable From Affiliate	0	166
OTHER NON-CURRENT ASSETS, net	53	56
Total assets	4,239	6,367
Accounts payable	0	1
Accounts payable to related companies	24	15
Interest payable	29	48
Price risk management liabilities	5	5
Accrued and other current liabilities	13	1
Current maturities of long-term debt	4	4
Total current liabilities	75	74
LONG-TERM DEBT, less current maturities	2,682	3,840
PREFERRED UNITS OF SUBSIDIARY	0	331
OTHER NON-CURRENT LIABILITIES	1	9
COMMITMENTS AND CONTINGENCIES
General Partner	(2)	0
Limited Partners	1,485	2,125
Accumulated other comprehensive loss	(2)	(12)
Total partners’ capital	1,481	2,113
Total liabilities and equity	$ 4,239	$ 6,367

XML

Equity (Change In ETE Common Units) (Details) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Partners' Capital Notes [Abstract]
Outstanding at December 31, 2012	280.0
Issuance of restricted units under equity incentive plans	0.8
Outstanding at June 30, 2013	280.8

XML

Supplemental Financial Statement Information (Tables)

6 Months Ended

Jun. 30, 2013

Schedule Of Balance Sheets

BALANCE SHEETS

(unaudited)

	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	72		$	9
Accounts receivable from related companies	8			11
Other current assets	1			3
Total current assets	81			23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,080			6,094
INTANGIBLE ASSETS, net	16			19
GOODWILL	9			9
NOTE RECEIVABLE FROM AFFILIATE	—			166
OTHER NON-CURRENT ASSETS, net	53			56
Total assets	$	4,239		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	24			15
Interest payable	29			48
Price risk management liabilities	5			5
Accrued and other current liabilities	13			1
Current maturities of long-term debt	4			4
Total current liabilities	75			74
LONG-TERM DEBT, less current maturities	2,682			3,840
PREFERRED UNITS	—			331
OTHER NON-CURRENT LIABILITIES	1			9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(2		)	—
Limited Partners	1,485			2,125
Accumulated other comprehensive loss	(2		)	(12		)
Total partners’ capital	1,481			2,113
Total liabilities and partners’ capital	$	4,239		$	6,367

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(23	)	$	(10	)	$	(29	)	$	(41	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(53		)	(63		)	(117		)	(106		)
Bridge loan related fees	—			—			—			(62		)
Gains (losses) on interest rate derivatives	6			(9		)	6			(9		)
Equity in earnings of unconsolidated affiliates	198			127			366			434
Other, net	(2		)	9			(10		)	4
INCOME BEFORE INCOME TAXES	126			54			216			220
Income tax benefit	(1		)	—			(1		)	—
NET INCOME	127			54			217			220
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—			—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	127		$	54		$	217		$	219

Parent Company [Member]

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
	2013			2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	427		$	203
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds received in (paid for) acquisitions and other transactions, net	1,332			(1,113		)
Contributions to affiliate	—			(445		)
Note receivable from affiliate	—			(221		)
Payments received on note receivable from affiliate	166			55
Net cash provided by (used in) investing activities	1,498			(1,724		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	440			2,005
Principal payments on debt	(1,602		)	(107		)
Distributions to partners	(360		)	(315		)
Redemption of Preferred Units	(340		)	—
Debt issuance costs	—			(77		)
Net cash provided by (used in) financing activities	(1,862		)	1,506
DECREASE IN CASH AND CASH EQUIVALENTS	63			(15		)
CASH AND CASH EQUIVALENTS, beginning of period	9			18
CASH AND CASH EQUIVALENTS, end of period	$	72		$	3

XML

Cash And Cash Equivalents (Tables)

6 Months Ended

Jun. 30, 2013

Supplemental Cash Flow Information [Abstract]

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

Non-cash investing and financing activities are as follows:

	Six Months Ended June 30,
	2013			2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	538		$	485
Accrued advances to affiliates	$	—		$	4
Net losses from subsidiary common unit transactions	$	(364	)	$	(14	)
AmeriGas limited partner interest received in Propane Contribution	$	—		$	1,123
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger	$	—		$	2,354
Subsidiary issuances of common units in connection with certain acquisitions	$	—		$	112

XML

Investments in Affiliates (Tables)

6 Months Ended

Jun. 30, 2013

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Revenue	$	5,356	$	1,045	$	9,502	$	2,411
Operating income	291		220		640		534
Net income	158		50		388		265

XML

Fair Value Measurements (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Preferred Units	$ 0	$ (331)
Fair Value, Measurements, Recurring [Member]
Interest rate derivatives, Asset Fair Value	40	55
Commodity derivatives, Asset Fair Value	128	156
Total Assets	168	211
Interest rate derivatives, Liability Fair Value	(122)	(235)
Preferred Units		(331)
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	(47)	(25)
Commodity derivatives, Liability Fair Value	(98)	(168)
Total Liabilities	(267)	(759)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Interest rate derivatives, Asset Fair Value	0	0
Commodity derivatives, Asset Fair Value	91	108
Total Assets	91	108
Interest rate derivatives, Liability Fair Value	0	0
Preferred Units		0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	(72)	(118)
Total Liabilities	(72)	(118)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Interest rate derivatives, Asset Fair Value	40	55
Commodity derivatives, Asset Fair Value	37	48
Total Assets	77	103
Interest rate derivatives, Liability Fair Value	(122)	(235)
Preferred Units		0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	(26)	(50)
Total Liabilities	(148)	(285)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Interest rate derivatives, Asset Fair Value	0	0
Commodity derivatives, Asset Fair Value	0	0
Total Assets	0	0
Interest rate derivatives, Liability Fair Value	0	0
Preferred Units		(331)
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	(47)	(25)
Commodity derivatives, Liability Fair Value	0	0
Total Liabilities	(47)	(356)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	2	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	2	2
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Condensate [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value		5
Commodity derivatives, Liability Fair Value		(8)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value		1
Commodity derivatives, Liability Fair Value		(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value		4
Commodity derivatives, Liability Fair Value		(7)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value		0
Commodity derivatives, Liability Fair Value		0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	9	27
Commodity derivatives, Liability Fair Value	(9)	(27)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	2	1
Commodity derivatives, Liability Fair Value	(2)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	8	2
Commodity derivatives, Liability Fair Value	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	2	1
Commodity derivatives, Liability Fair Value	(2)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 1 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	9	27
Commodity derivatives, Liability Fair Value	(9)	(27)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	8	2
Commodity derivatives, Liability Fair Value	(5)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value		0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 3 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	5	11
Commodity derivatives, Liability Fair Value	(9)	(18)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	3	3
Commodity derivatives, Liability Fair Value	(4)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	76	98
Commodity derivatives, Liability Fair Value	(59)	(103)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	1	3
Commodity derivatives, Liability Fair Value	(1)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Options - Puts [Member]
Commodity derivatives, Asset Fair Value	1	1
Commodity derivatives, Liability Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	1	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	5	11
Commodity derivatives, Liability Fair Value	(9)	(18)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	68	94
Commodity derivatives, Liability Fair Value	(54)	(94)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Options - Puts [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	3	3
Commodity derivatives, Liability Fair Value	(4)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	8	4
Commodity derivatives, Liability Fair Value	(5)	(9)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	1	3
Commodity derivatives, Liability Fair Value	(1)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Options - Puts [Member]
Commodity derivatives, Asset Fair Value	1	1
Commodity derivatives, Liability Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	1	1
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Basis Swaps IFERC/NYMEX [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Options - Puts [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 3 [Member] | Forward Physical Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	20	2
Commodity derivatives, Liability Fair Value	(7)	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	16	1
Commodity derivatives, Liability Fair Value	(6)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	4	1
Commodity derivatives, Liability Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	0
Commodity derivatives, Liability Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | Crude Oil [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	(1)
Fair Value, Measurements, Recurring [Member] | Crude Oil [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	(1)
Fair Value, Measurements, Recurring [Member] | Crude Oil [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] | Crude Oil [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	$ 0

XML

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

6 Months Ended

Jun. 30, 2013

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.

	June 30, 2013		December 31, 2012
Current	$	40	$	46
Non-current	160		166
Total environmental liabilities	$	200	$	212

XML

Acquisitions (Narrative) (Details) (USD $) Share data in Millions, unless otherwise specified			1 Months Ended				6 Months Ended
	Jun. 30, 2013	Oct. 05, 2012 Sunoco Merger [Member]	Apr. 30, 2013 SUGS Contribution [Member]	Mar. 21, 2013 Holdco Acquisition [Member]	Apr. 30, 2013 Southern Union [Member] SUGS Contribution [Member]	Apr. 30, 2013 ETP [Member] SUGS Contribution [Member]	Jun. 30, 2013 Holdco [Member]	Jun. 30, 2013 ETE [Member] Holdco [Member]	Jun. 30, 2013 ETP [Member] Holdco [Member]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	$ 1,040,000,000
Business Acquisition, Purchase Price Allocation, Liabilities Assumed	19,000,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares			31.4
Regency Class F Units to be Issued in SUGS Contribution			6.3
Business Acquisition, Purchase Price Allocation, Current Assets, Cash and Cash Equivalents					463,000,000	30,000,000
Estimated Closing Adjustments				68,000,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							60.00%	60.00%	100.00%
Business Acquisition Units Issued				49.5
Business Combination, Consideration Transferred		2,600,000,000
Business Acquisition Units Acquired		55
Business Acquisition, Cost of Acquired Entity, Cash Paid				$ 1,400,000,000

XML

Debt Obligations (Senior Notes) (Details) (USD $)	6 Months Ended			1 Months Ended							6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 24, 2013	Jan. 31, 2013 ETP [Member]	Jan. 31, 2013 Sunoco Logistics [Member]	Jun. 30, 2013 Regency 4.50% Senior Notes Due 2023 [Member]	Jun. 30, 2013 3.6% Senior Notes due February 1, 2023 [Member]	Jun. 30, 2013 5.15% Senior Notes due February 1, 2043 [Member]	Jun. 30, 2013 3.45% Senior Notes due January 2023 [Member]	Jun. 30, 2013 4.95% Senior Notes due January 2043 [Member]	Jun. 30, 2013 Regency Senior Notes [Member]	Jun. 24, 2013 7.60% Senior Notes, due February 1, 2024 [Member]	Jun. 24, 2013 8.25% Senior Notes, due November 14, 2029 [Member]	Jun. 24, 2013 Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount						$ 600,000,000
Senior Notes							800,000,000	450,000,000	350,000,000	350,000,000
Debt Instrument, Interest Rate, Stated Percentage						4.50%	3.60%	5.15%	3.45%	4.95%	9.375%	7.60%	8.25%
Proceeds from Issuance of Long-term Debt	6,063,000,000	5,964,000,000									178,000,000
Debt Instrument, Increase, Accrued Interest											7,000,000
Repayments of long-term debt	5,305,000,000	3,101,000,000									163,000,000
Proceeds from Issuance of Senior Long-term Debt				1,240,000,000	691,000,000
ETP Note Exchange			$ 1,090,000,000
Percent of SUG Notes Exchanged for ETP Notes												77.00%	89.00%	91.00%

XML

Equity (Tables)

6 Months Ended

Jun. 30, 2013

Schedule of Net IDR Subsidies [Table Text Block]

As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:

	Quarters Ending
	March 31		June 30		September 30		December 31		Total Year
2013	N/A		N/A		$	21.00	$	21.00	$	42.00
2014	$	27.25	$	27.25	27.25		27.25		109.00
2015	13.25		13.25		13.25		13.25		53.00
2016	5.50		5.50		5.50		5.50		22.00

Change In ETE Common Units

The change in ETE Common Units during the six months ended June 30, 2013 was as follows:

	Number of Units
Outstanding at December 31, 2012	280.0
Issuance of restricted units under equity incentive plans	0.8
Outstanding at June 30, 2013	280.8

Accumulated Other Comprehensive Income

The following table presents the components of accumulated other comprehensive loss, net of tax:

	June 30, 2013			December 31, 2012
Net gains (losses) on commodity related hedges	$	6		$	(3	)
Foreign currency translation adjustment	(1		)	—
Actuarial loss related to pensions and other postretirement benefits	(9		)	(10		)
Equity investments, net	(5		)	(9		)
Subtotal	(9		)	(22		)
Amounts attributable to noncontrolling interest	7			10
Total accumulated other comprehensive loss, net of tax	$	(2	)	$	(12	)

Parent Company [Member]

Quarterly Distributions Of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 19, 2013	$	0.635
March 31, 2013	May 6, 2013	May 17, 2013	0.645
June 30, 2013	August 5, 2013	August 19, 2013	0.655

ETP [Member]

Quarterly Distributions Of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.89375
March 31, 2013	May 6, 2013	May 15, 2013	0.89375
June 30, 2013	August 5, 2013	August 14, 2013	0.89375

Regency [Member]

Quarterly Distributions Of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.460
March 31, 2013	May 6, 2013	May 13, 2013	0.460
June 30, 2013	August 5, 2013	August 14, 2013	0.465

Sunoco Logistics [Member]

Quarterly Distributions Of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 8, 2013	February 14, 2013	$	0.5450
March 31, 2013	May 9, 2013	May 15, 2013	0.5725
June 30, 2013	August 8, 2013	August 14, 2013	0.6000

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended				0 Months Ended	6 Months Ended		3 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012	Jun. 30, 2013 Regency 4.50% Senior Notes Due 2023 [Member]	Jan. 12, 2012 AmeriGas [Member]	Jun. 30, 2013 State and Local Jurisdiction [Member]	Jun. 30, 2013 U.S Federal [Member]	Jun. 30, 2013 Attorney General of Commonwealth [Member]
Contingent Residual Support Agreement, Amount							$ 1,550,000,000
Debt Instrument, Face Amount						600,000,000
Debt Instrument, Interest Rate, Stated Percentage						4.50%
Guarantor Obligations, Current Carrying Value						600,000,000
Lease Expiration Date			Dec. 31, 2056
Operating Leases, Rent Expense	32,000,000	12,000,000	65,000,000	19,000,000
Operating Leases, Rent Expense, Contingent Rentals	6,000,000		10,000,000
Operating Leases, Income Statement, Sublease Revenue	5,000,000		10,000,000
Maximum Amount of Attorney's Fees								950,000	250,000
Loss Contingency Accrual, at Carrying Value	37,000,000		37,000,000		42,000,000
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	$ 11,000,000		$ 18,000,000

XML

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 1	$ 13	$ 2	$ 16
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	(1)	32	4	19
Amount of Gain/(Loss) Recognized in Income on Derivatives	78	(24)	40	(8)
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	3	0	(1)	(11)
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	1	13	2	16
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	(1)	32	4	19
Amount of Gain/(Loss) Recognized in Income on Derivatives	35	12	14	12
Commodity Derivatives [Member] | Deferred Gas Purchases [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	2	0	(3)	0
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	46	(44)	52	(17)
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (8)	$ 8	$ (22)	$ 8

XML

Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended				9 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Pretax curtailment gain									$ 75
Noncurrent refund liability									60
Gain on curtailment of other postretirement benefit plans	0		0		0		(15)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	3		2	[1]	5		2	[1]
Interest cost	9		(1)	[1]	18		(1)	[1]
Expected return on plan assets	(15)		(1)	[1]	(30)		(1)	[1]
Actuarial loss amortization					(1)		0	[1]
Settlement credits					(2)		0	[1]
Gain on curtailment of other postretirement benefit plans					0	[2]	0	[1],[2]
Net periodic benefit cost subtotal	(3)		0	[1]	(8)		0	[1]
Regulatory adjustment(3)	2	[3]	0	[1],[3]	4	[3]	0	[1],[3]
Net periodic benefit cost	(1)		0	[1]	(4)		0	[1]
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1		0	[1]	1		0	[1]
Interest cost	1		1	[1]	3		1	[1]
Expected return on plan assets	(1)		(2)	[1]	(4)		(2)	[1]
Actuarial loss amortization					0		0	[1]
Settlement credits					0		0	[1]
Gain on curtailment of other postretirement benefit plans					0	[2]	(15)	[1],[2]	(15)
Net periodic benefit cost subtotal	1		(1)	[1]	0		(16)	[1]
Regulatory adjustment(3)	(3)	[3]	1	[1],[3]	0	[3]	1	[1],[3]
Net periodic benefit cost	$ (2)		$ 0	[1]	$ 0		$ (15)	[1]

[1] (1) The three and six months ended June 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.

[2] (2) Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million.

[3] (3) In its distribution operations, Southern Union recovers 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 amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

XML

Cash And Cash Equivalents (Schedule Of Non-Cash Investing & Financing Activities) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 538	$ 485
Accrued advances to affiliates	0	4
Net losses from subsidiary common unit transactions	(364)	(14)
AmeriGas limited partner interest received in Propane Contribution	0	1,123
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger	0	2,354
ETP [Member]
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with certain acquisitions	$ 0	$ 112

XML

Price Risk Management Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Total derivatives assets	$ 233	$ 215
Total derivatives liabilities	(332)	(439)
Designated as Hedging Instrument [Member]
Total derivatives assets	20	8
Total derivatives liabilities	(2)	(10)
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	20	8
Total derivatives liabilities	(2)	(10)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	213	207
Total derivatives liabilities	(330)	(429)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	81	110
Total derivatives liabilities	(80)	(116)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	91	40
Total derivatives liabilities	(76)	(44)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	40	55
Total derivatives liabilities	(122)	(235)
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	(47)	(25)
Current Assets Held For Sale [Member] | Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	1	1
Total derivatives liabilities	0	0
Non-Current Assets Held For Sale [Member] | Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	0	1
Total derivatives liabilities	0	0
Current Liabilities Held For Sale [Member] | Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	$ (5)	$ (9)
Fair Value Hedging [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member] | Non Trading [Member] | Natural Gas [Member]
Derivative, Nonmonetary Notional Amount	(10,530,000)	(18,655,000)

XML

Supplemental Financial Statement Information

6 Months Ended

Jun. 30, 2013

Supplemental Financial Statement Information

Supplemental Financial Statement Information

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS

(unaudited)

	June 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	72		$	9
Accounts receivable from related companies	8			11
Other current assets	1			3
Total current assets	81			23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,080			6,094
INTANGIBLE ASSETS, net	16			19
GOODWILL	9			9
NOTE RECEIVABLE FROM AFFILIATE	—			166
OTHER NON-CURRENT ASSETS, net	53			56
Total assets	$	4,239		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—		$	1
Accounts payable to related companies	24			15
Interest payable	29			48
Price risk management liabilities	5			5
Accrued and other current liabilities	13			1
Current maturities of long-term debt	4			4
Total current liabilities	75			74
LONG-TERM DEBT, less current maturities	2,682			3,840
PREFERRED UNITS	—			331
OTHER NON-CURRENT LIABILITIES	1			9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(2		)	—
Limited Partners	1,485			2,125
Accumulated other comprehensive loss	(2		)	(12		)
Total partners’ capital	1,481			2,113
Total liabilities and partners’ capital	$	4,239		$	6,367

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(23	)	$	(10	)	$	(29	)	$	(41	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(53		)	(63		)	(117		)	(106		)
Bridge loan related fees	—			—			—			(62		)
Gains (losses) on interest rate derivatives	6			(9		)	6			(9		)
Equity in earnings of unconsolidated affiliates	198			127			366			434
Other, net	(2		)	9			(10		)	4
INCOME BEFORE INCOME TAXES	126			54			216			220
Income tax benefit	(1		)	—			(1		)	—
NET INCOME	127			54			217			220
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—			—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	127		$	54		$	217		$	219

STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
	2013			2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	427		$	203
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds received in (paid for) acquisitions and other transactions, net	1,332			(1,113		)
Contributions to affiliate	—			(445		)
Note receivable from affiliate	—			(221		)
Payments received on note receivable from affiliate	166			55
Net cash provided by (used in) investing activities	1,498			(1,724		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	440			2,005
Principal payments on debt	(1,602		)	(107		)
Distributions to partners	(360		)	(315		)
Redemption of Preferred Units	(340		)	—
Debt issuance costs	—			(77		)
Net cash provided by (used in) financing activities	(1,862		)	1,506
DECREASE IN CASH AND CASH EQUIVALENTS	63			(15		)
CASH AND CASH EQUIVALENTS, beginning of period	9			18
CASH AND CASH EQUIVALENTS, end of period	$	72		$	3

XML

Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 660	$ 1,036
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	630	360
Deferred income taxes	68	4
Gain on curtailment of other postretirement benefit plans	0	(15)
Amortization of finance costs charged to interest	(33)	6
Bridge loan related fees	0	62
Non-cash compensation expense	27	24
Gain on deconsolidation of Propane Business	0	(1,057)
Losses on disposal of assets	5	2
Losses on extinguishment of debt	7	123
LIFO valuation adjustment	(16)	0
Equity in earnings of unconsolidated affiliates	(144)	(97)
Distributions from unconsolidated affiliates	191	101
Other non-cash	25	29
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidation (see Note 2)	(293)	(153)
Net cash provided by operating activities	1,127	425
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions, net of cash received	(5)	(10)
Capital expenditures (excluding allowance for equity funds used during construction)	(1,504)	(1,294)
Contributions in aid of construction costs	11	12
Contributions to unconsolidated affiliates	(2)	(20)
Distributions from unconsolidated affiliates in excess of cumulative earnings	59	76
Proceeds from the sale of assets	53	34
Cash proceeds from contribution of propane operations	0	1,443
Other	(46)	(2)
Net cash used in investing activities	(1,434)	(2,733)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	6,063	5,964
Repayments of long-term debt	(5,305)	(3,101)
Subsidiary equity offerings, net of issue costs	1,218	390
Distributions to partners	(360)	(315)
Debt issuance costs	(37)	(98)
Distributions to noncontrolling interest	(684)	(447)
Capital contributions received from noncontrolling interest	12	10
Redemption of Preferred Units	(340)	0
Other, net	(11)	(3)
Net cash provided by financing activities	556	2,400
INCREASE IN CASH AND CASH EQUIVALENTS	249	92
CASH AND CASH EQUIVALENTS, beginning of period	372	126
CASH AND CASH EQUIVALENTS, end of period	621	218
Southern Union Merger [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions, net of cash received	$ 0	$ (2,972)

XML

Acquisitions

6 Months Ended

Jun. 30, 2013

ACQUISITIONS AND DIVESTITURE [Abstract]

Acquisitions

ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Sale of Distribution Operations

In December 2012, Southern Union entered into definitive purchase and sale agreements dated December 14, 2012 (collectively, the “Purchase and Sale Agreements”) with each of Plaza Missouri Acquisition, Inc. (“Laclede Missouri”) and Plaza Massachusetts Acquisition, Inc. (“Laclede Massachusetts”), both of which are subsidiaries of The Laclede Group, Inc. (together, the “Laclede Entities”), pursuant to which Laclede Missouri has agreed to acquire the assets of Southern Union’s Missouri Gas Energy division, and Laclede Massachusetts has agreed to acquire the assets of Southern Union’s New England Gas Company division. Total consideration for the acquisitions will be $1.04 billion, subject to customary closing adjustments, less the assumption of $19 million of debt. In February 2013, the Laclede Entities entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that will allow a subsidiary of APUC to assume the right of the Laclede Entities to purchase the assets of Southern Union’s New England Gas Company division, subject to certain approvals. The sale of Southern Union’s Missouri Gas Energy division is expected to close on or after September 1, 2013. The sale of Southern Union’s New England Gas Company division is expected to close in the fourth quarter of 2013.

For the three and six months ended June 30, 2013 and the period from March 26, 2012 to June 30, 2012, the distribution operations have been classified as discontinued operations in the consolidated statements of operations. The assets and liabilities of the disposal group have been classified as assets and liabilities held for sale as of June 30, 2013 and December 31, 2012.

SUGS Contribution

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”). The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, a wholly-owned subsidiary of Southern Union, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “Holdco Acquisition”). As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.

Sunoco Merger

On October 5, 2012, Sam Acquisition Corporation, a Pennsylvania corporation and a wholly-owned subsidiary of ETP, completed its merger with Sunoco. Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and $2.6 billion in cash.

Management is continuing to validate certain assumptions made in connection with the purchase price allocation of Sunoco; therefore, certain assets and/or liabilities may be adjusted.

XML

Inventories (Notes)

6 Months Ended

Jun. 30, 2013

Inventory, Net [Abstract]

Inventories

INVENTORIES:

Inventories consisted of the following:

	June 30, 2013		December 31, 2012
Natural gas and NGLs	$	357	$	338
Crude oil	548		418
Refined products	531		572
Other	205		194
Total inventories	$	1,641	$	1,522

ETP utilizes commodity derivatives to manage price volatility associated with 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.

XML

Other Information (Other Current Assets) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Other Information [Abstract]
Deposits paid to vendors	$ 34	$ 41
Prepaid expenses and other	251	270
Total other current assets	$ 285	$ 311

XML

Investments in Affiliates

6 Months Ended

Jun. 30, 2013

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. ETP owned approximately 30 million AmeriGas common units as of June 30, 2013. On July 12, 2013, ETP sold 7.5 million of its AmeriGas common units, which were received in connection with the Partnership’s contribution of its retail propane operations to AmeriGas in January 2012, for net proceeds of $346 million.

• Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, an approximate 5,400 mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc.

• FEP. ETP owns a 50% interest in the FEP, which owns an approximately 185-mile 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 a 450-mile intrastate pipeline system.

• MEP. Regency owns a 50% interest in MEP, which owns approximately 500 miles of 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.

• PES. Sunoco owns an approximate 30% non-operating interest in PES, a joint venture with The Carlyle Group, L.P., which owns a refinery in Philadelphia. Sunoco has a ten-year supply contract for gasoline and diesel produced at the refinery for its retail marketing business.

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Revenue	$	5,356	$	1,045	$	9,502	$	2,411
Operating income	291		220		640		534
Net income	158		50		388		265

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

XML

Investments in Affiliates Investments in Affiliates Narrative (Details) (USD $) In Millions, unless otherwise specified				6 Months Ended
	Jul. 12, 2013	Jun. 30, 2013 AmeriGas [Member]	Jun. 30, 2013 Citrus [Member]	Jun. 30, 2013 FGT [Member]	Jun. 30, 2013 Fayetteville Express Pipeline, LLC [Member]	Jun. 30, 2013 RIGS Haynesville Partnership Co. [Member]	Jun. 30, 2013 Midcontinent Express Pipeline, LLC [Member]	Jun. 30, 2013 PES Joint Venture [Member]
Schedule of Equity Method Investments [Line Items]
Investment Owned, Balance, Shares		30
AmeriGas common units sold by ETP	7.5
Proceeds from ETP's sale of AmeriGas common units	$ 346
Interest ownership			50.00%		50.00%	49.99%	50.00%	30.00%
Percentage Ownership Operating Facility				100.00%

XML

Inventories (Tables)

6 Months Ended

Jun. 30, 2013

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:

	June 30, 2013		December 31, 2012
Natural gas and NGLs	$	357	$	338
Crude oil	548		418
Refined products	531		572
Other	205		194
Total inventories	$	1,641	$	1,522

XML

Income Taxes (Tables)

6 Months Ended

Jun. 30, 2013

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

The following table summarizes the Partnership’s income tax expense from continuing operations:

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Income tax expense from continuing operations	$	89		$	5		$	87		$	7
Effective tax rate	21		%	7		%	12		%	1		%

XML

Price Risk Management Assets And Liabilities (Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 6	$ 3	$ 8	$ 25
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	6	(17)	8	5
Interest Rate Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 0	$ 20	$ 0	$ 20

XML

Reportable Segments (Tables)

6 Months Ended

Jun. 30, 2013

Operating Segments [Member]

Financial Information By Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Segment Adjusted EBITDA:
Investment in ETP	$	1,069		$	642		$	2,025		$	1,136
Investment in Regency	153			137			274			257
Corporate and Other	(23		)	(10		)	(29		)	(41		)
Adjustments and Eliminations	(36		)	(41		)	(55		)	(43		)
Total	1,163			728			2,215			1,309
Depreciation and amortization	(318		)	(206		)	(630		)	(360		)
Interest expense, net of interest capitalized	(305		)	(282		)	(615		)	(495		)
Bridge loan related fees	—			—			—			(62		)
Gain on deconsolidation of Propane Business	—			1			—			1,057
Gains (losses) on interest rate derivatives	46			(44		)	52			(17		)
Non-cash unit-based compensation expense	(11		)	(12		)	(27		)	(24		)
Unrealized gains (losses) on commodity risk management activities	22			37			23			(47		)
Losses on extinguishment of debt	(7		)	(8		)	(7		)	(123		)
Gain on curtailment of other postretirement benefit plans	—			—			—			15
LIFO valuation adjustment	(22		)	—			16			—
Equity in earnings of unconsolidated affiliates	54			22			144			97
Adjusted EBITDA related to unconsolidated affiliates	(184		)	(140		)	(388		)	(281		)
Adjusted EBITDA related to discontinued operations	(23		)	(27		)	(63		)	(34		)
Other, net	3			4			(4		)	2
Income from continuing operations before income tax expense	$	418		$	73		$	716		$	1,037

Assets Segments [Member]

Financial Information By Segment

	June 30, 2013			December 31, 2012
Total assets:
Investment in ETP	$	43,651		$	43,320
Investment in Regency	8,521			8,123
Corporate and Other	704			707
Adjustments and Eliminations	(2,733		)	(3,246		)
Total	$	50,143		$	48,904

Sales Revenue, Segment [Member]

Financial Information By Segment

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenues:
Investment in ETP:
Revenues from external customers	$	11,529		$	1,584		$	22,366		$	2,903
Intersegment revenues	22			12			39			16
	11,551			1,596			22,405			2,919
Investment in Regency:
Revenues from external customers	628			509			1,163			880
Intersegment revenues	11			2			16			6
	639			511			1,179			886
Corporate and Other:
Revenues from external customers	—			4			—			2
Adjustments and Eliminations	(127		)	(234		)	(342		)	(260		)
Total revenues	$	12,063		$	1,877		$	23,242		$	3,547

Investment In ETP [Member]

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

Investment in ETP

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Intrastate Transportation and Storage	$	558	$	452	$	1,209	$	899
Interstate Transportation and Storage	354		310		677		452
Midstream	588		629		1,338		1,088
NGL Transportation and Services	420		148		766		302
Investment in Sunoco Logistics	4,256		—		7,713		—
Retail Marketing	5,291		—		10,508		—
All Other	84		57		194		178
Total revenues	11,551		1,596		22,405		2,919
Less: Intersegment revenues	22		12		39		16
Revenues from external customers	$	11,529	$	1,584	$	22,366	$	2,903

Investment In Regency [Member]

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

Investment in Regency

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Gathering and Processing	$	583	$	462	$	1,069	$	787
Contract Services	52		44		101		90
Corporate and others	4		5		9		9
Total revenues	639		511		1,179		886
Less: Intersegment revenues	11		2		16		6
Revenues from external customers	$	628	$	509	$	1,163	$	880

XML

Price Risk Management Assets And Liabilities (Gross FV and Netting Offset) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 233	$ 215
Derivative Liability, Fair Value, Gross Liability	(332)	(439)
Netting [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	253	177
Derivative Liability, Fair Value, Gross Liability	236	248
Derivative Asset, Fair Value, Gross Liability	(63)	(25)
Derivative Liability, Fair Value, Gross Asset	63	25
Derivative Asset, Fair Value, Net	179	152
Derivative Liability, Fair Value, Net	(157)	(162)
Other Derivatives Not Designated as Hedging Instruments Assets at Fair Value	54	63
Other Derivatives Not Designated as Hedging Instruments Liabilities at Fair Value	(175)	(277)
Netting [Member] | Bi-lateral contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	82	28
Derivative Liability, Fair Value, Gross Liability	81	27
Netting [Member] | Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	171	149
Derivative Liability, Fair Value, Gross Liability	155	221
Netting [Member] | Asset Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Collateral Paid To OTC Counterparties	0	0
Payments on Margin Deposits	(11)	0
Netting [Member] | Liability Fair Value, Netting Offset [Member]
Derivatives, Fair Value [Line Items]
Collateral Paid To OTC Counterparties	0	2
Payments on Margin Deposits	$ 16	$ 59

XML

Redeemable Preferred Units Narrative (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2013
Payments for Repurchase of Redeemable Preferred Stock	$ 300
Preferred Stock Redemption Premium		$ 40
ETE Preferred Units [Member]
Preferred Units, Outstanding	3,000,000	3,000,000

XML

Debt Obligations (Parent Company) (Narrative) (Details) (USD $)						3 Months Ended	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 ETE Senior Secured Revolving Credit Facilities [Member]	Jun. 30, 2013 LIBOR [Member]	Jun. 30, 2013 Base Rate Loans [Member]	Jun. 30, 2013 ETE Senior Secured Term Loan [Member]	Jun. 30, 2013 Holdco [Member]	Jun. 30, 2013 Holdco [Member] ETE [Member]
Secured Debt	$ 2,000,000,000
Debt Instrument, Basis Spread on Variable Rate				3.00%	2.00%
Outstanding borrowings			0
Line of Credit Facility, Remaining Borrowing Capacity			200,000,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							60.00%	60.00%
Proceeds from Issuance or Sale of Equity						1,100,000,000
Long-term Debt	$ 22,760,000,000	$ 22,050,000,000				$ 900,000,000

XML

Fair Value Measurements (Narrative) (Details) (USD $) In Billions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Fair Value Measurements [Abstract]
Debt obligations, fair value	$ 23.59	$ 24.15
Long-term Debt	$ 22.76	$ 22.05

XML

Consolidated Statements Of Operations (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
REVENUES:
Natural gas sales	$ 864	$ 554	$ 1,837	$ 1,057
NGL sales	787	592	1,500	1,120
Crude sales	3,992	0	7,193	0
Gathering, transportation and other fees	815	596	1,555	1,085
Refined product sales	4,650	0	9,312	0
Other	955	135	1,845	285
Total revenues	12,063	1,877	23,242	3,547
COSTS AND EXPENSES:
Cost of products sold	10,565	962	20,372	1,977
Operating expenses	375	236	724	406
Depreciation and amortization	318	206	630	360
Selling, general and administrative	161	108	341	255
Total costs and expenses	11,419	1,512	22,067	2,998
OPERATING INCOME	644	365	1,175	549
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(305)	(282)	(615)	(495)
Bridge loan related fees	0	0	0	(62)
Equity in earnings of unconsolidated affiliates	54	22	144	97
Gain on deconsolidation of Propane Business	0	1	0	1,057
Losses on extinguishment of debt	(7)	(8)	(7)	(123)
Gains (losses) on interest rate derivatives	46	(44)	52	(17)
Other, net	(14)	19	(33)	31
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	418	73	716	1,037
Income tax expense from continuing operations	89	5	87	7
INCOME FROM CONTINUING OPERATIONS	329	68	629	1,030
Income from discontinued operations	9	7	31	6
NET INCOME	338	75	660	1,036
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	211	21	443	816
NET INCOME ATTRIBUTABLE TO PARTNERS	127	54	217	220
GENERAL PARTNER’S INTEREST IN NET INCOME	0	0	0	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$ 127	$ 54	$ 217	$ 219
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	0.44	0.18	0.72	0.85
Diluted	0.44	0.18	0.72	0.84
NET INCOME PER LIMITED PARTNER UNIT:
Basic	0.45	0.19	0.77	0.87
Diluted	0.45	0.19	0.77	0.86

XML

Debt Obligations

6 Months Ended

Jun. 30, 2013

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

ETE Term Loan

On March 23, 2012, ETE entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, as Administrative Agent, and the other lenders from time to time party thereto (the “Term Lenders”), which became effective on March 26, 2012. The Term Credit Agreement has a scheduled maturity date of March 26, 2017, with an option for ETE to extend the term subject to the terms and conditions set forth therein. Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2 billion. Interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of ETE for each interest period. The applicable margin for LIBOR rate loans is 3.00% and the applicable margin for base rate loans is 2.00%.  Proceeds of the borrowings under the Term Credit Agreement were used to partially fund the Southern Union Merger, to repay amounts outstanding under the Parent Company Credit Facility, and to pay transaction fees and expenses related to the Southern Union Merger, the new Term Credit Agreement and other transactions incidental thereto.

During the three months ended June 30, 2013, proceeds from ETP’s acquisition of ETE’s 60% interest in Holdco were used to repay borrowings of $1.10 billion on ETE’s Term Credit Agreement. The total amount outstanding as of June 30, 2013 was $900 million.

Senior Notes

Regency Senior Notes

In April 2013, in conjunction with Southern Union’s contribution of SUGS to Regency, Regency issued $600 million senior notes in a private placement that mature on November 1, 2023 and bear interest at 4.5% payable semi-annually. In April 3013, Regency also delivered notice of redemption to the holders of its 2016 Senior Notes. In June 2013, Regency redeemed all of the $163 million outstanding 9.375% Senior Notes due 2016 for $178 million cash, including accrued and unpaid interest of $7 million and other fees and expenses.

ETP Senior Notes

In January 2013, ETP issued $800 million of 3.6% Senior Notes due February 2023 and $450 million of 5.15% Senior Notes due February 2043. ETP used the net proceeds of $1.24 billion from the offering to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.

Sunoco Logistics Senior Notes

In January 2013, Sunoco Logistics issued $350 million of 3.45% Senior Notes due January 2023 and $350 million of 4.95% Senior Notes due January 2043. The net proceeds of $691 million from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facilities and for general partnership purposes.

ETP Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion total principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066.  These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates.  In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.

Revolving Credit Facilities

Parent Company Credit Facility

As of June 30, 2013, there were no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.

ETP Credit Facility

ETP has a $2.5 billion revolving credit facility (the “ETP Credit Facility”) that expires in October 2016. 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 ETP’s current and future unsecured debt.

As of June 30, 2013, the ETP Credit Facility had a balance of $900 million outstanding and the amount available for future borrowings was $1.49 billion after taking into account letters of credit of $107 million. The weighted average interest rate on the total amount outstanding as of June 30, 2013 was 1.70%.

Regency Credit Facility

In May 2013, Regency entered into an agreement to increase the borrowing capacity of the Regency Credit Facility to $1.2 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018.

As of June 30, 2013, the Regency Credit Facility had a balance outstanding of $535 million in revolving credit loans and approximately $13 million in letters of credit. The total amount available under the Regency Credit Facility, as of June 30, 2013, which was reduced by any letters of credit, was approximately $652 million, and the weighted average interest rate on the total amount outstanding as of June 30, 2013 was 2.20%.

Southern Union Credit Facilities

Proceeds from the SUGS Contribution were used to repay $240 million of borrowings under the Eighth Amended and Restated Revolving Credit Agreement (the “Southern Union Credit Facility”) and the facility was terminated.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains two credit facilities to fund its working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 and a $200 million unsecured credit facility which expires in August 2013. There were no outstanding borrowings under these credit facilities as of June 30, 2013.

West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility. Outstanding borrowings under this credit facility were $35 million as of June 30, 2013.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of June 30, 2013.

XML

Consolidated Statement Of Equity (USD $) In Millions, unless otherwise specified	Total	General Partner	Common Unitholders	Accumulated Other Comprehensive Loss	Noncontrolling Interest
Balance, December 31, 2012 at Dec. 31, 2012	$ 16,350	$ 0	$ 2,125	$ (12)	$ 14,237
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Distributions to partners	(360)	(1)	(359)	0	0
Distributions to noncontrolling interest	(684)	0	0	0	(684)
Subsidiary units issued for cash	1,218	0	142	0	1,076
Noncontrolling Interest, Increase from Equity Issuance or Sale of Parent Equity Interest	0	(1)	(506)	0	507
Non-cash compensation expense, net of units tendered by employees for tax withholdings	26	0	0	0	26
Capital contributions from noncontrolling interest	12	0	0	0	12
Other, net	1	0	(1)	4	(2)
Deemed Distribution related to SUGS Transaction	(133)	0	(133)	0	0
Other comprehensive income, net of tax	10	0	0	6	4
Net income	660	0	217	0	443
Balance, June 30, 2013 at Jun. 30, 2013	$ 17,100	$ (2)	$ 1,485	$ (2)	$ 15,619

XML

Equity (Quarterly Distributions Of Available Cash) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	6 Months Ended		3 Months Ended
	Jun. 30, 2013	Mar. 31, 2013	Jun. 30, 2013 Parent Company [Member]	Mar. 31, 2013 Parent Company [Member]	Dec. 31, 2012 Parent Company [Member]	Jun. 30, 2013 ETP [Member]	Mar. 31, 2013 ETP [Member]	Dec. 31, 2012 ETP [Member]	Jun. 30, 2013 Regency [Member]	Mar. 31, 2013 Regency [Member]	Dec. 31, 2012 Regency [Member]	Jun. 30, 2013 Sunoco Logistics [Member]	Mar. 31, 2013 Sunoco Logistics [Member]	Dec. 31, 2012 Sunoco Logistics [Member]
Equity Distribution Agreement Commissions	$ 4
Common Units Issued In Connection With The Dividend Reinvestment Plan	1.0
Equity Distribution Agreement, Capacity	$ 800	$ 200
Record Date			Aug. 05, 2013	May 06, 2013	Feb. 07, 2013	Aug. 05, 2013	May 06, 2013	Feb. 07, 2013	Aug. 05, 2013	May 06, 2013	Feb. 07, 2013	Aug. 08, 2013	May 09, 2013	Feb. 08, 2013
Payment Date			Aug. 19, 2013	May 17, 2013	Feb. 19, 2013	Aug. 14, 2013	May 15, 2013	Feb. 14, 2013	Aug. 14, 2013	May 13, 2013	Feb. 14, 2013	Aug. 14, 2013	May 15, 2013	Feb. 14, 2013
Distributions paid, rate per unit			$ 0.655	$ 0.645	$ 0.635	$ 0.89375	$ 0.89375	$ 0.89375	$ 0.465	$ 0.460	$ 0.460	$ 0.600	$ 0.5725	$ 0.5450

XML

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 621	$ 372
Accounts receivable, net	3,318	3,057
Accounts receivable from related companies	82	71
Inventories	1,641	1,522
Exchanges receivable	50	55
Price risk management assets	54	25
Current assets held for sale	102	184
Other current assets	285	311
Total current assets	6,153	5,597
PROPERTY, PLANT AND EQUIPMENT	31,848	30,388
ACCUMULATED DEPRECIATION	(2,661)	(2,104)
PROPERTY, PLANT AND EQUIPMENT, net	29,187	28,284
NON-CURRENT ASSETS HELD FOR SALE	1,000	985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,640	4,737
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	24	43
GOODWILL	6,372	6,434
INTANGIBLE ASSETS, net	2,221	2,291
OTHER NON-CURRENT ASSETS, net	546	533
Total assets	50,143	48,904
LIABILITIES AND EQUITY
Accounts payable	3,385	3,107
Accounts payable to related companies	14	15
Exchanges payable	153	156
Price risk management liabilities	57	115
Accrued and other current liabilities	1,542	1,754
Current maturities of long-term debt	899	613
Current liabilities held for sale	75	85
Total current liabilities	6,125	5,845
NON-CURRENT LIABILTIES HELD FOR SALE	140	142
LONG-TERM DEBT, less current maturities	21,860	21,440
PREFERRED UNITS	0	331
DEFERRED INCOME TAXES	3,861	3,566
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	135	162
OTHER NON-CURRENT LIABILITIES	849	995
COMMITMENTS AND CONTINGENCIES (Note 14)
PREFERRED UNITS OF SUBSIDIARY	73	73
EQUITY:
General Partner	(2)	0
Limited Partners:
Common Unitholders	1,485	2,125
Accumulated other comprehensive loss	(2)	(12)
Total partners’ capital	1,481	2,113
Noncontrolling interest	15,619	14,237
Total equity	17,100	16,350
Total liabilities and equity	$ 50,143	$ 48,904

XML

Debt Obligations (ETP Credit Facility) (Narrative) (Details) (ETP Credit Facility [Member], USD $) In Millions, unless otherwise specified	Jun. 30, 2013
ETP Credit Facility [Member]
Outstanding borrowings	$ 900
Amount available for future borrowings	1,490
Letters of Credit Outstanding, Amount	107
Weighted average interest rate on amount outstanding	1.70%
Line of Credit Facility, Current Borrowing Capacity	$ 2,500

XML

Reportable Segments Narrative (Details) (Regency [Member], Lone Star L.L.C. [Member])	6 Months Ended
	Jun. 30, 2013
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%

XML

Reportable Segments Operating Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 1,163	$ 728	$ 2,215	$ 1,309
Depreciation and amortization	(318)	(206)	(630)	(360)
Interest Expense, net of interest capitalized	(305)	(282)	(615)	(495)
Bridge loan related fees	0	0	0	(62)
Gain on deconsolidation of Propane Business	0	1	0	1,057
Gains (losses) on interest rate derivatives	46	(44)	52	(17)
Non-cash unit-based compensation expense	(11)	(12)	(27)	(24)
Unrealized Gain (Loss) on commodity risk management activities	22	37	23	(47)
Losses on extinguishment of debt	(7)	(8)	(7)	(123)
Gain on curtailment of other postretirement benefit plans	0	0	0	15
LIFO valuation adjustment	(22)	0	16	0
Equity in earnings of unconsolidated affiliates	54	22	144	97
Adjusted EBITDA related to unconsolidated affiliates	(184)	(140)	(388)	(281)
Adjusted EBITDA related to discontinued operations	(23)	(27)	(63)	(34)
Other than Temporary Impairment Losses, Investments	3	4	(4)	2
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	418	73	716	1,037
Investment In ETP [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,069	642	2,025	1,136
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	153	137	274	257
Corporate And Other [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(23)	(10)	(29)	(41)
Adjustments And Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ (36)	$ (41)	$ (55)	$ (43)

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value Measurements [Abstract]

Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:

	Fair Value Measurements at June 30, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	40		$	—		$	40		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	76			68			8			—
Options — Calls	1			—			1			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Forwards/Swaps	20			16			4			—
Power:
Forwards	9			—			9			—
Futures	2			2			—
Options — Calls	8			—			8			—
Total commodity derivatives	128			91			37			—
Total Assets	$	168		$	91		$	77		$	—
Liabilities:
Interest rate derivatives	$	(122	)	$	—		$	(122	)	$	—
Embedded derivatives in the Regency Preferred Units	(47		)	—			—			(47		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(9		)	(9		)	—			—
Swing Swaps IFERC	(4		)	—			(4		)	—
Fixed Swaps/Futures	(59		)	(54		)	(5		)	—
Options — Calls	(1		)	—			(1		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(7		)	(6		)	(1		)	—
Power:
Forwards	(9		)	—			(9		)	—
Futures	(2		)	(2		)	—			—
Options — Calls	(5		)	—			(5		)	—
Crude	(1		)	(1		)	—			—
Total commodity derivatives	(98		)	(72		)	(26		)	—
Total Liabilities	$	(267	)	$	(72	)	$	(148	)	$	(47	)

	Fair Value Measurements at December 31, 2012
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	55		$	—		$	55		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	11			11			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	98			94			4			—
Options — Calls	3			—			3			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Swaps	2			1			1			—
Power:
Forwards	27			—			27			—
Futures	1			1			—			—
Options — Calls	2			—			2			—
Refined Products	5			1			4			—
Total commodity derivatives	156			108			48			—
Total Assets	$	211		$	108		$	103		$	—
Liabilities:
Interest rate derivatives	$	(235	)	$	—		$	(235	)	$	—
Preferred Units	(331		)	—			—			(331		)
Embedded derivatives in the Regency Preferred Units	(25		)	—			—			(25		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(2		)	—			(2		)	—
Fixed Swaps/Futures	(103		)	(94		)	(9		)	—
Options — Calls	(3		)	—			(3		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Swaps	(4		)	(3		)	(1		)	—
Power:
Forwards	(27		)	—			(27		)	—
Futures	(2		)	(2		)	—			—
Refined Products	(8		)	(1		)	(7		)	—
Total commodity derivatives	(168		)	(118		)	(50		)	—
Total Liabilities	$	(759	)	$	(118	)	$	(285	)	$	(356	)

Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the six months ended June 30, 2013. There were no transfers between the fair value hierarchy levels during the six months ended June 30, 2013 or 2012.

Balance, December 31, 2012	$	(356	)
Realized loss included in other income (expense)	(9		)
Net unrealized loss included in other income (expense)	(22		)
Redemption of Preferred Units	340
Balance, June 30, 2013	$	(47	)

XML

Other Information

6 Months Ended

Jun. 30, 2013

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:

	June 30, 2013		December 31, 2012
Deposits paid to vendors	$	34	$	41
Prepaid expenses and other	251		270
Total other current assets	$	285	$	311

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	June 30, 2013		December 31, 2012
Interest payable	$	323	$	334
Customer advances and deposits	99		61
Accrued capital expenditures	402		427
Accrued wages and benefits	123		250
Taxes payable other than income taxes	273		208
Income taxes payable	37		41
Deferred income taxes	84		130
Other	201		303
Total accrued and other current liabilities	$	1,542	$	1,754

XML

Inventories (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Inventory, Net [Abstract]
Natural gas and NGLs	$ 357	$ 338
Crude oil	548	418
Refined products	531	572
Other	205	194
Total inventories	$ 1,641	$ 1,522

XML

Reportable Segments Revenues (External and Intersegment) by Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues	$ 12,063	$ 1,877	$ 23,242	$ 3,547
Investment In ETP [Member]
Revenue from External Customers	11,529	1,584	22,366	2,903
Intersegment Revenues	22	12	39	16
Segment Reporting Information, Revenue for Reportable Segment	11,551	1,596	22,405	2,919
Revenues	11,551	1,596	22,405	2,919
Investment In Regency [Member]
Revenue from External Customers	628	509	1,163	880
Intersegment Revenues	11	2	16	6
Segment Reporting Information, Revenue for Reportable Segment	639	511	1,179	886
Revenues	639	511	1,179	886
Corporate And Other [Member]
Revenue from External Customers	0	4	0	2
Segment Reporting Information, Revenue for Reportable Segment
Adjustments And Eliminations [Member]
Revenue from External Customers	$ (127)	$ (234)	$ (342)	$ (260)

XML

Debt Obligations (Sunoco Logistics Credit Facilities) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Sunoco Logistics Revolving Credit Facility, due August 2016 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 350
Sunoco Logistics Revolving Credit Facility, due August 2013 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200
Outstanding borrowings	0
Sunoco Logistics Revolving Credit Facility, due April 2015 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	35
Outstanding borrowings	$ 35

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Accrued Environmental Liabilities (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Environmental Exit Cost [Line Items]
Current	$ 40	$ 46
Non-current	160	166
Total environmental liabilities	$ 200	$ 212

XML

Operations And Organization (Schedule Of Equity Interests) (Details)	6 Months Ended
	Jun. 30, 2013
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
Holdco [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
ETP [Member] | Lone Star L.L.C. [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	70.00%
ETP [Member] | Holdco [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%
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%

XML

Price Risk Management Assets And Liabilities (Tables)

6 Months Ended

Jun. 30, 2013

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)	June 30, 2013		December 31, 2012
ETE	March 2017	Pay a fixed rate of 1.25% and receive a floating rate	$	500	$	500
ETP	July 2013 (2)	Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	100		400
ETP	July 2014 (2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	400		400
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	600		600
ETP	February 2023	Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%	400		—
Southern Union	November 2016	Pay a fixed rate of 2.91% and receive a floating rate	75		75
Southern Union	November 2021	Pay a fixed rate of 3.75% and receive a floating rate	450		450

⁽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.

Fair Value Of Derivative Instruments

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	June 30, 2013		December 31, 2012		June 30, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	20	$	8	$	(2	)	$	(10	)
	20		8		(2		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	81	$	110	$	(80	)	$	(116	)
Commodity derivatives	91		40		(76		)	(44		)
Current assets held for sale	1		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		(5		)	(9		)
Interest rate derivatives	40		55		(122		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(47		)	(25		)
	213		207		(330		)	(429		)
Total derivatives	$	233	$	215	$	(332	)	$	(439	)

In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.

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
Contract Type	Balance Sheet Location	June 30, 2013			December 31, 2012			June 30, 2013			December 31, 2012
Bi-lateral contracts	Price risk management asset (liability)	$	82		$	28		$	(81	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	171			149			(155		)	(221		)
	Gross fair value	253			177			(236		)	(248		)
Collateral paid to OTC counterparties	Other current assets (liabilities)	—			—			—			2
Counterparty netting	Price risk management asset (liability)	(63		)	(25		)	63			25
Payments on margin deposit	Other current assets (liabilities)	(11		)	—			16			59
	Net fair value	179			152			(157		)	(162		)
	Other derivatives – gross	54			63			(175		)	(277		)
	Total derivatives	$	233		$	215		$	(332	)	$	(439	)

Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	6	$	(17	)	$	8	$	5
Interest rate derivatives	—		20			—		20
Total	$	6	$	3		$	8	$	25

Partnership's Derivative Assets And Liabilities Amount Of Gain (Loss) Recognized

	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 June 30,				Six Months Ended June 30,
		2013		2012		2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	1	$	13	$	2	$	16
Total		$	1	$	13	$	2	$	16

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,					Six Months Ended June 30,
		2013			2012		2013		2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(1	)	$	32	$	4	$	19
Total		$	(1	)	$	32	$	4	$	19

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2013			2012			2013			2012
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	3		$	—		$	(1	)	$	(11	)
Commodity derivatives — Non-Trading	Cost of products sold	35			12			14			12
Commodity derivatives — Non-Trading	Deferred gas purchases	2			—			(3		)	—
Interest rate derivatives	Gains (losses) on interest rate derivatives	46			(44		)	52			(17		)
Embedded derivatives	Other income	(8		)	8			(22		)	8
Total		$	78		$	(24	)	$	40		$	(8	)

ETP [Member]

Outstanding Commodity-Related Derivatives

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

	June 30, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	9,650,000	2013-2015	—		—
Basis Swaps IFERC/NYMEX (1)	(37,702,500)	2013-2014	(30,980,000	)	2013-2014
Power (Megawatt):
Forwards	145,078	2013	19,650		2013
Futures	(557,260)	2013	(1,509,300	)	2013
Options — Calls	(1,200)	2013	1,656,400		2013
Crude (Bbls) — Futures	(80,000)	2013	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	8,770,000	2013-2014	150,000		2013
Swing Swaps IFERC	20,060,000	2013	(83,292,500	)	2013
Fixed Swaps/Futures	23,435,000	2013-2015	27,077,500		2013
Forward Physical Contracts	1,758,402	2013-2014	11,689,855		2013-2014
Natural Gas Liquid (Bbls):
Forwards/Swaps	(597,000)	2013-2014	(30,000	)	2013
Refined Products (Bbls) — Futures	(1,227,000)	2013	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(10,530,000)	2013	(18,655,000	)	2013
Fixed Swaps/Futures	(32,682,500)	2013	(44,272,500	)	2013
Hedged Item — Inventory	32,682,500	2013	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(2,300,000)	2013	—		—
Fixed Swaps/Futures	(4,140,000)	2013	(8,212,500	)	2013
Natural Gas Liquid (Bbls):
Forwards/Swaps	(690,000)	2013	(930,000	)	2013
Crude (Bbls) — Futures	(210,000)	2013	—		—
Refined Products (Bbls) — Futures	—	—	(98,000	)	2013

⁽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:

	June 30, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	18,672,000	2013-2014	8,395,000	2013-2014
Propane (Gallons):
Forwards/Swaps	20,496,000	2013	3,318,000	2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	234,000	2013-2014	243,000	2013-2014
WTI Crude Oil (Barrels):
Forwards/Swaps	700,000	2013-2014	356,000	2014

XML

Other Information (Tables)

6 Months Ended

Jun. 30, 2013

Other Information [Abstract]

Other Current Assets

Other current assets consisted of the following:

	June 30, 2013		December 31, 2012
Deposits paid to vendors	$	34	$	41
Prepaid expenses and other	251		270
Total other current assets	$	285	$	311

Accrued And Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	June 30, 2013		December 31, 2012
Interest payable	$	323	$	334
Customer advances and deposits	99		61
Accrued capital expenditures	402		427
Accrued wages and benefits	123		250
Taxes payable other than income taxes	273		208
Income taxes payable	37		41
Deferred income taxes	84		130
Other	201		303
Total accrued and other current liabilities	$	1,542	$	1,754

XML

Net Income Per Limited Partner Unit

6 Months Ended

Jun. 30, 2013

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Income from continuing operations	$	329	$	68	$	629	$	1,030
Less: Income from continuing operations attributable to noncontrolling interest	206		19		428		815
Income from continuing operations, net of noncontrolling interest	123		49		201		215
Less: General Partner’s interest in income from continuing operations	—		—		—		1
Income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	214
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	280.5		280.0		280.2		253.3
Basic income from continuing operations per Limited Partner unit	$	0.44	$	0.18	$	0.72	$	0.85
Basic income from discontinued operations per Limited Partner unit	$	0.01	$	0.01	$	0.05	$	0.02
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	214
Dilutive effect of equity-based compensation of subsidiaries	—		—		—		(1		)
Diluted income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	213
Weighted average limited partner units	280.5		280.0		280.2		253.3
Diluted income from continuing operations per Limited Partner unit	$	0.44	$	0.18	$	0.72	$	0.84
Diluted income from discontinued operations per Limited Partner unit	$	0.01	$	0.01	$	0.05	$	0.02

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Income Tax Disclosure [Abstract]
Income tax expense from continuing operations	$ 89	$ 5	$ 87	$ 7
Effective Income Tax Rate, Continuing Operations	21.00%	7.00%	12.00%	1.00%

XML

Net Income Per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 2013

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 June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Income from continuing operations	$	329	$	68	$	629	$	1,030
Less: Income from continuing operations attributable to noncontrolling interest	206		19		428		815
Income from continuing operations, net of noncontrolling interest	123		49		201		215
Less: General Partner’s interest in income from continuing operations	—		—		—		1
Income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	214
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	280.5		280.0		280.2		253.3
Basic income from continuing operations per Limited Partner unit	$	0.44	$	0.18	$	0.72	$	0.85
Basic income from discontinued operations per Limited Partner unit	$	0.01	$	0.01	$	0.05	$	0.02
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	214
Dilutive effect of equity-based compensation of subsidiaries	—		—		—		(1		)
Diluted income from continuing operations available to Limited Partners	$	123	$	49	$	201	$	213
Weighted average limited partner units	280.5		280.0		280.2		253.3
Diluted income from continuing operations per Limited Partner unit	$	0.44	$	0.18	$	0.72	$	0.84
Diluted income from discontinued operations per Limited Partner unit	$	0.01	$	0.01	$	0.05	$	0.02

XML

Investments in Affiliates Schedule of Equity Method Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Schedule of Equity Method Investments [Line Items]
Revenue	$ 5,356	$ 1,045	$ 9,502	$ 2,411
Operating income	291	220	640	534
Net income	$ 158	$ 50	$ 388	$ 265

XML

Equity

6 Months Ended

Jun. 30, 2013

Partners' Capital Notes [Abstract]

Equity

EQUITY:

ETE Common Units Issued

The change in ETE Common Units during the six months ended June 30, 2013 was as follows:

	Number of Units
Outstanding at December 31, 2012	280.0
Issuance of restricted units under equity incentive plans	0.8
Outstanding at June 30, 2013	280.8

Sales of Common Units by Subsidiaries

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

As a result of ETP’s and Regency’s issuances of common units during the six months ended June 30, 2013, we recognized decreases in partners’ capital of $364 million.

Sales of Common Units by ETP

In January 2013 and May 2013, ETP entered into Equity Distribution Agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the six months ended June 30,2013, ETP received proceeds of $387 million, net of commissions of $4 million, from the issuance of units pursuant to the Equity Distribution Agreements, which proceeds were used for general partnership purposes. ETP also received $26 million net of commissions, in July 2013 from the settlement of transactions initiated in June 2013 under these agreements. Approximately $609 million of ETP Common Units remain available to be issued under these agreements.

During the six months ended June 30,2013, distributions of $46 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 1.0 million ETP Common Units. As of June 30, 2013, a total of 3.3 million ETP Common Units remain available to be issued under the existing registration statement.

In April 2013, ETP issued 13.8 million ETP Common Units at $48.05 per ETP Common Unit in an underwritten public offering. Proceeds, net of commissions, of $657 million from the offering were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes.

ETP Class G Units

In April 2013, all of the outstanding ETP Class F Units, which were issued in connection with the Sunoco Merger, were exchanged for ETP Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in ETP’s consolidated financial statements.

ETP Class H Units

On August 7, 2013, ETP, ETE and ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE (“ETE Holdings”) entered into an Exchange and Redemption Agreement, pursuant to which ETP has agreed to redeem and cancel 50.2 million of its common units representing limited partner interests (the “Redeemed Units”) currently owned by ETE Holdings in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”) which will generally be entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50% of the profits, losses, and other items allocated to ETP by Sunoco Partners LLC (“Sunoco Partners”), the general partner of Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ending September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Quarterly Distributions of Available Cash” below.

This transaction is subject to certain customary closing conditions. In the Exchange and Redemption Agreement, ETP, ETE and ETE Holdings have made customary representations and warranties and have agreed to customary covenants relating to this transaction.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 19, 2013	$	0.635
March 31, 2013	May 6, 2013	May 17, 2013	0.645
June 30, 2013	August 5, 2013	August 19, 2013	0.655

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.89375
March 31, 2013	May 6, 2013	May 15, 2013	0.89375
June 30, 2013	August 5, 2013	August 14, 2013	0.89375

Following are incentive distributions ETE has agreed to relinquish:

• In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of the incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.

• In conjunction with the Holdco transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.

• As discussed in Note 2, in connection with ETP’s acquisition of ETE’s 60% interest in Holdco on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.

As discussed under “Class H Units” above, ETP has agreed to make incremental cash distributions of $329 million over 15 quarters, commencing with the quarter ending September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition.

As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:

	Quarters Ending
	March 31		June 30		September 30		December 31		Total Year
2013	N/A		N/A		$	21.00	$	21.00	$	42.00
2014	$	27.25	$	27.25	27.25		27.25		109.00
2015	13.25		13.25		13.25		13.25		53.00
2016	5.50		5.50		5.50		5.50		22.00

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.460
March 31, 2013	May 6, 2013	May 13, 2013	0.460
June 30, 2013	August 5, 2013	August 14, 2013	0.465

In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego incentive distributions with respect to the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 8, 2013	February 14, 2013	$	0.5450
March 31, 2013	May 9, 2013	May 15, 2013	0.5725
June 30, 2013	August 8, 2013	August 14, 2013	0.6000

Accumulated Other Comprehensive Loss

The following table presents the components of accumulated other comprehensive loss, net of tax:

	June 30, 2013			December 31, 2012
Net gains (losses) on commodity related hedges	$	6		$	(3	)
Foreign currency translation adjustment	(1		)	—
Actuarial loss related to pensions and other postretirement benefits	(9		)	(10		)
Equity investments, net	(5		)	(9		)
Subtotal	(9		)	(22		)
Amounts attributable to noncontrolling interest	7			10
Total accumulated other comprehensive loss, net of tax	$	(2	)	$	(12	)

XML

Other Information (Accrued And Other Current Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Other Information [Abstract]
Interest payable	$ 323	$ 334
Customer advances and deposits	99	61
Accrued capital expenditures	402	427
Accrued wages and benefits	123	250
Taxes payable other than income taxes	273	208
Income taxes payable	37	41
Deferred income taxes	84	130
Other	201	303
Total accrued and other current liabilities	$ 1,542	$ 1,754

XML

Fair Value Measurements

6 Months Ended

Jun. 30, 2013

Fair Value Measurements [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS:

We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units 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 marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements, 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. At December 31, 2012, the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.

Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value of our consolidated debt obligations as of June 30, 2013 and December 31, 2012 was $23.59 billion and $24.15 billion, respectively. As of June 30, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $22.76 billion and $22.05 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 June 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:

	Fair Value Measurements at June 30, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	40		$	—		$	40		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	76			68			8			—
Options — Calls	1			—			1			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Forwards/Swaps	20			16			4			—
Power:
Forwards	9			—			9			—
Futures	2			2			—
Options — Calls	8			—			8			—
Total commodity derivatives	128			91			37			—
Total Assets	$	168		$	91		$	77		$	—
Liabilities:
Interest rate derivatives	$	(122	)	$	—		$	(122	)	$	—
Embedded derivatives in the Regency Preferred Units	(47		)	—			—			(47		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(9		)	(9		)	—			—
Swing Swaps IFERC	(4		)	—			(4		)	—
Fixed Swaps/Futures	(59		)	(54		)	(5		)	—
Options — Calls	(1		)	—			(1		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(7		)	(6		)	(1		)	—
Power:
Forwards	(9		)	—			(9		)	—
Futures	(2		)	(2		)	—			—
Options — Calls	(5		)	—			(5		)	—
Crude	(1		)	(1		)	—			—
Total commodity derivatives	(98		)	(72		)	(26		)	—
Total Liabilities	$	(267	)	$	(72	)	$	(148	)	$	(47	)

	Fair Value Measurements at December 31, 2012
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	55		$	—		$	55		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	11			11			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	98			94			4			—
Options — Calls	3			—			3			—
Options — Puts	1			—			1			—
Forward Physical Contracts	1			—			1			—
NGLs — Swaps	2			1			1			—
Power:
Forwards	27			—			27			—
Futures	1			1			—			—
Options — Calls	2			—			2			—
Refined Products	5			1			4			—
Total commodity derivatives	156			108			48			—
Total Assets	$	211		$	108		$	103		$	—
Liabilities:
Interest rate derivatives	$	(235	)	$	—		$	(235	)	$	—
Preferred Units	(331		)	—			—			(331		)
Embedded derivatives in the Regency Preferred Units	(25		)	—			—			(25		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(2		)	—			(2		)	—
Fixed Swaps/Futures	(103		)	(94		)	(9		)	—
Options — Calls	(3		)	—			(3		)	—
Options — Puts	(1		)	—			(1		)	—
NGLs — Swaps	(4		)	(3		)	(1		)	—
Power:
Forwards	(27		)	—			(27		)	—
Futures	(2		)	(2		)	—			—
Refined Products	(8		)	(1		)	(7		)	—
Total commodity derivatives	(168		)	(118		)	(50		)	—
Total Liabilities	$	(759	)	$	(118	)	$	(285	)	$	(356	)

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the six months ended June 30, 2013. There were no transfers between the fair value hierarchy levels during the six months ended June 30, 2013 or 2012.

Balance, December 31, 2012	$	(356	)
Realized loss included in other income (expense)	(9		)
Net unrealized loss included in other income (expense)	(22		)
Redemption of Preferred Units	340
Balance, June 30, 2013	$	(47	)

XML

Operations And Organization

6 Months Ended

Jun. 30, 2013

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”); and

• ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.

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. 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 19 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’s 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.

• Energy Transfer Interstate Holdings, LLC, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales, which 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.

▪ 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.

▪ Holdco, a Delaware limited liability company that indirectly owns Southern Union and Sunoco. As discussed in Note 2, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. Sunoco and Southern Union operations are described as follows:

◦ Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation, storage and distribution of natural gas in the United States. As discussed in Note 2, 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.

◦ Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores primarily on the east coast and in the midwest region of the United States.

• Regency is a publicly traded partnership engaged in the gathering and processing, contract 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 Haynesville, Eagle Ford, Barnett, Fayetteville, Bone Spring, Avalon and Marcellus shales, as well as the Permian Delaware basin and the mid-continent region. Its assets are located in Texas, Louisiana, Arkansas, Pennsylvania, California, Mississippi, Alabama, West Virginia and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

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.

• 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, 2012, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of June 30, 2013 and for the three months ended June 30, 2013 and 2012, 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 June 30, 2013, and the Partnership’s results of operations and cash flows for the three and six months endedJune 30, 2013 and 2012. 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, 2012, as filed with the SEC on March 1, 2013.

Certain prior period amounts have been reclassified to conform to the 2013 presentation. These reclassifications had no impact on net income or total equity.

As a result of the Southern Union Merger in March 2012 and the Holdco Transaction in October 2012, the periods presented herein do not include activities from Southern Union or Sunoco prior to the consummation of the respective mergers and/or transactions.

XML

Debt Obligations (Regency Credit Facility) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Regency Credit Facility [Member]
Outstanding borrowings	$ 535
Letters of Credit Outstanding, Amount	13
Amount available for future borrowings	652
Weighted average interest rate on amount outstanding	2.20%
Line of Credit Facility, Maximum Borrowing Capacity	1,200
Regency Credit Facility [Member]
Line of Credit Facility, Maximum Borrowing Capacity	$ 300

XML

Fair Value Measurements (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Level 3 [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2012 Level 3 [Member] Fair Value, Measurements, Recurring [Member]
Balance, December 31, 2012			$ (47)	$ (356)
Net unrealized loss included in other income (expense)	22
Realized loss included in other income (expense)	(9)
Redemption of Preferred Units	340	0
Balance, June 30, 2013			$ (47)	$ (356)

XML

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 1,127	$ 425
Proceeds received in (paid for) acquisitions and other transactions, net	(5)	(10)
Net cash provided by (used in) investing activities	(1,434)	(2,733)
Proceeds from borrowings	6,063	5,964
Repayments of long-term debt	(5,305)	(3,101)
Distributions to partners	(360)	(315)
Redemption of Preferred Units	340	0
Debt issuance costs	(37)	(98)
Net cash provided by (used in) financing activities	556	2,400
DECREASE IN CASH AND CASH EQUIVALENTS	249	92
CASH AND CASH EQUIVALENTS, beginning of period	372	126
CASH AND CASH EQUIVALENTS, end of period	621	218
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	427	203
Proceeds received in (paid for) acquisitions and other transactions, net	1,332	(1,113)
Contributions to affiliate	0	445
Note receivable from affiliate	0	221
Payments received on note receivable from affiliate	166	55
Net cash provided by (used in) investing activities	1,498	(1,724)
Proceeds from borrowings	440	2,005
Repayments of long-term debt	(1,602)	(107)
Distributions to partners	(360)	(315)
Redemption of Preferred Units	(340)	0
Debt issuance costs	0	(77)
Net cash provided by (used in) financing activities	(1,862)	1,506
DECREASE IN CASH AND CASH EQUIVALENTS	63	(15)
CASH AND CASH EQUIVALENTS, beginning of period	9	18
CASH AND CASH EQUIVALENTS, end of period	$ 72	$ 3

XML

Benefits (Tables)

6 Months Ended

Jun. 30, 2013

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 June 30,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	3		$	1		$	2		$	—
Interest cost	9			1			(1		)	1
Expected return on plan assets	(15		)	(1		)	(1		)	(2		)
	(3		)	1			—			(1		)
Regulatory adjustment(3)	2			(3		)	—			1
Net periodic benefit cost	$	(1	)	$	(2	)	$	—		$	—

	Six Months Ended June 30,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	5		$	1		$	2		$	—
Interest cost	18			3			(1		)	1
Expected return on plan assets	(30		)	(4		)	(1		)	(2		)
Actuarial loss amortization	1			—			—			—
Settlement credits	(2		)	—			—			—
Curtailment recognition(2)	—			—			—			(15		)
	(8		)	—			—			(16		)
Regulatory adjustment(3)	4			—			—			1
Net periodic benefit cost	$	(4	)	$	—		$	—		$	(15	)

⁽¹⁾  The three and six months ended June 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.

⁽²⁾  Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $60 million.  As such, the net curtailment gain recognition was $15 million.

⁽³⁾  In its distribution operations, Southern Union recovers 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 amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

XML

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$ (161)	$ (108)	$ (341)	$ (255)
Interest expense	(305)	(282)	(615)	(495)
Equity in earnings of unconsolidated affiliates	54	22	144	97
Losses on interest rate derivatives	46	(44)	52	(17)
Other, net	(14)	19	(33)	31
Income tax expense (benefit)	89	5	87	7
NET INCOME ATTRIBUTABLE TO PARTNERS	127	54	217	220
GENERAL PARTNER’S INTEREST IN NET INCOME	0	0	0	1
LIMITED PARTNERS' INTEREST IN NET INCOME	127	54	217	219
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	(23)	(10)	(29)	(41)
Interest expense	(53)	(63)	(117)	(106)
Bridge loan related fees	0	0	0	(62)
Equity in earnings of unconsolidated affiliates	198	127	366	434
Losses on interest rate derivatives	6	(9)	6	(9)
Other, net	(2)	9	(10)	4
INCOME BEFORE INCOME TAXES	126	54	216	220
Income tax expense (benefit)	(1)	0	(1)	0
NET INCOME ATTRIBUTABLE TO PARTNERS	127	54	217	220
GENERAL PARTNER’S INTEREST IN NET INCOME	0	0	0	1
LIMITED PARTNERS' INTEREST IN NET INCOME	$ 127	$ 54	$ 217	$ 219

XML

Price Risk Management Assets And Liabilities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Deposits with counterparties	$ 34	$ 41
ETP [Member]
Expected gains (losses) related to derivatives to be reclassified into earnings over next year related to amounts currently reported an AOCI	6
Deposits with counterparties	34
Regency [Member]
Notional Amount of Credit Risk Derivatives	13
Derivative, Fair Value, Amount Offset Against Collateral, Net	1
Price Risk Management Liabilities [Member]
Option Premiums		$ 7

XML

Equity (Accumulated Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Partners' Capital Notes [Abstract]
Net gains (losses) on commodity related hedges	$ 6	$ (3)
Foreign currency translation adjustment	(1)	0
Actuarial loss related to pensions and other postretirement benefits	(9)	(10)
Equity investments, net	(5)	(9)
Subtotal	(9)	(22)
Amounts attributable to noncontrolling interest	(7)	(10)
Accumulated other comprehensive loss	$ (2)	$ (12)

XML

Benefits

6 Months Ended

Jun. 30, 2013

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 June 30,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	3		$	1		$	2		$	—
Interest cost	9			1			(1		)	1
Expected return on plan assets	(15		)	(1		)	(1		)	(2		)
	(3		)	1			—			(1		)
Regulatory adjustment(3)	2			(3		)	—			1
Net periodic benefit cost	$	(1	)	$	(2	)	$	—		$	—

	Six Months Ended June 30,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	5		$	1		$	2		$	—
Interest cost	18			3			(1		)	1
Expected return on plan assets	(30		)	(4		)	(1		)	(2		)
Actuarial loss amortization	1			—			—			—
Settlement credits	(2		)	—			—			—
Curtailment recognition(2)	—			—			—			(15		)
	(8		)	—			—			(16		)
Regulatory adjustment(3)	4			—			—			1
Net periodic benefit cost	$	(4	)	$	—		$	—		$	(15	)

⁽¹⁾  The three and six months ended June 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.

⁽²⁾  Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees.  The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million.  Such gain was offset by establishment of a non-current refund liability in the amount of $60 million.  As such, the net curtailment gain recognition was $15 million.

⁽³⁾  In its distribution operations, Southern Union recovers 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 amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

XML

Redeemable Preferred Units (Notes)

6 Months Ended

Jun. 30, 2013

Temporary Equity Disclosure [Abstract]

Redeemable Preferred Units [Text Block]

PREFERRED UNITS:

On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units from Regency GP Acquirer L.P. (“GE Regency”) pursuant to a Preferred Unit Redemption Agreement, dated as of March 28, 2013, between ETE and GE Regency. Prior to the Redemption, on March 28, 2013, ETE paid GE Regency $40 million in cash in exchange for GE Regency relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.

XML

Price Risk Management Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) (Interest Rate Derivatives [Member], USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013		Dec. 31, 2012
March 2017 [Member] | Parent Company [Member]
Notional Amount	$ 500		$ 500
Type	Pay a fixed rate of 1.25% and receive a floating rate	[1]
July 2013 [Member] | ETP [Member]
Notional Amount	100	[2]	400	[2]
Type	Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	[1]
July 2014 [Member] | ETP [Member]
Notional Amount	400	[2]	400	[2]
Type	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	[1]
July 2018 [Member] | ETP [Member]
Notional Amount	600		600
Type	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	[1]
November 2016 [Member] | Southern Union [Member]
Notional Amount	75		75
Type	Pay a fixed rate of 2.91% and receive a floating rate
November 2021 [Member] | Southern Union [Member]
Notional Amount	450		450
Type	Pay a fixed rate of 3.75% and receive a floating rate
February 2023 [Member] | ETP [Member]
Notional Amount	$ 400		$ 0
Type	Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%	[1]

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

[2] (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.

XML

Related Party Transactions

6 Months Ended

Jun. 30, 2013

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 (see Note 18).

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

6 Months Ended

Jun. 30, 2013

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

FERC Audit

The FERC is currently conducting an audit of Panhandle Eastern Pipe Line Company, LP, a subsidiary of Southern Union, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention.  A draft audit report was received on July 19, 2013 noting no issues that would have a material impact on the Partnership’s historical financial position or results of operations.

Contingent Residual Support Agreement — AmeriGas

In connection with the closing of the contribution of ETP’s propane operations in January 2013, 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.

PEPL Holdings Guarantee of Collection

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

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 $12 million for the three months endedJune 30, 2013 and 2012, respectively, which include contingent rentals totaling $6 million in the three months ended June 30, 2013.  For the six months ended June 30, 2013 and 2012, rental expense for operating leases totaled $65 million and $19 million, respectively, which include contingent rentals totaling $10 million in the six months ended June 30, 2013.  During the three and six months ended June 30, 2013, $5 million and $10 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.

Sunoco Litigation

Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania.  Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.

Litigation Relating to the Southern Union Merger

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  The lawsuits were styled Jaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas and Magda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas.  The lawsuits were consolidated into an action styled In re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas.  Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty.  The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders.  The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief.  On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE.  Three of the lawsuits also named Merger Sub as a defendant.  These lawsuits are styled: Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS; KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS; LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; and Memo v. Southern Union Company, et al., C.A. No. 6639-CS.  These cases were consolidated with the following style: In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery.  The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action.  On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice.  In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

The Texas case remains pending, and discovery is ongoing.

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 June 30, 2013, Sunoco was a defendant in two lawsuits involving one state and Puerto Rico.  These cases are venued in a multidistrict proceeding in a New York federal court.  Both 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.

Discovery is proceeding in these cases.  There has been insufficient information developed about the plaintiffs’ legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate 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 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.

Other Litigation and Contingencies

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the “ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union.  The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas.  Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants.  Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union.  On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action.  On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment.  Defendants filed a reply on December 19, 2012.  On December 20, 2012, the court conducted an oral hearing on the motion.  Plaintiffs filed a post-hearing sur-reply on January 7, 2013.  On January 16, 2013, the Court granted defendants’ motion for summary judgment.  The parties agreed to settle the matter and executed a memorandum of understanding. The parties are drafting a stipulation of settlement (with proposed judgment) and will have a settlement hearing likely in August 2013 for the Court to approve the settlement, which will dispose of the case. It is unlikely the Court will reject the settlement.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses.  For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage.  If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency.  As of June 30, 2013 and December 31, 2012, accruals of approximately $37 million and $42 million 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 June 30, 2013 or December 31, 2012 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Will Price.  Will Price, an individual, filed actions in the U.S. District Court for the District of Kansas for damages against a number of companies, including Panhandle, alleging mis-measurement of natural gas volumes and Btu content, resulting in lower royalties to mineral interest owners.  On September 19, 2009, the Court denied plaintiffs’ request for class certification.  Plaintiffs have filed a motion for reconsideration, which the Court denied on March 31, 2010.  Panhandle believes that its measurement practices conformed to the terms of its FERC natural gas tariffs, which were filed with and approved by the FERC.  As a result, Southern Union believes that it has meritorious defenses to the Will Price lawsuit (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Panhandle complied with the terms of its tariffs).  Panhandle will continue to vigorously defend the case.  Southern Union believes it has no liability associated with this proceeding.

Litigation Related to Incident at JJ's Restaurant.  On February 19, 2013, there was a natural gas explosion at JJ's Restaurant located at 910 W. 48th Street in Kansas City, Missouri.  One person died and media reports indicate that up to fifteen people were transported to area hospitals.  The extent and nature of those injuries are currently unknown.  The restaurant building was destroyed in the explosion and fire.  Immediately surrounding buildings sustained damage, but the full extent of that damage is unknown at this time.  A contractor, Heartland Midwest LLC, was in the process of installing cable for Time Warner Cable and hit a natural gas line while directionally boring.  The utility locates for the work were done by USIC Locating Services, Inc., a utility infrastructure locating company engaged by Missouri Gas Energy to locate and mark underground gas lines (and engaged by others to mark other underground facilities).  Several parties have retained counsel, and to date, nine lawsuits have been filed in the Circuit Court of Jackson County, Missouri, against numerous defendants.  MGE and MGE employee, Michael Palier, are defendants in all but one of the lawsuits (Palier v. Time Warner).  The lawsuits filed to date include Simmons v. MGE, Case No. 1316-CV07265 (no trial date set); Tanner v. MGE, Case No. 1316-CV09906 (no trial date set), JJ's Restaurant v. MGE, Case No. 1316-CV11288 (two trial dates set on January 12, 2015 and April 6, 2015); Meek v. MGE, Case No. 1316-CV13523 (no trial date set); Cramer v. MGE, Case No. 1316-CV13738 (no trial date set); Plazaview, LLC v. MGE, Case No. 1316-CV16817 (no trial date set); Mingos v. MGE, Case No. 1316-CV18072 (no trial date set); Palier v. Time Warner, Case No. 1316-CV18684 (no trial date set); and Couture v. MGE, Case No. 1316-CV18787 (no trial date set).  Discovery in the pending lawsuits is ongoing.  No demands have been made in any of the pending lawsuits.  The Partnership anticipates that more lawsuits will be filed.  The Missouri Public Service Commission and the Occupational Safety and Health Administration investigations are ongoing.  The Partnership will assess its potential exposure as the matter progresses as no estimate can be made at this time.

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 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. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union 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.  Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities.  We are unable to estimate any losses or range of losses that could result from such developments.  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.

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.

• Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to manufactured gas plants (“MGPs”) and may also be responsible for the removal of old MGP structures.

• 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 of June 30, 2013, Sunoco had been named as a PRP at 39 identified 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.

	June 30, 2013		December 31, 2012
Current	$	40	$	46
Non-current	160		166
Total environmental liabilities	$	200	$	212

During the three and six months ended June 30, 2013, the Partnership recorded $11 million and $18 million, respectively, of expenditures related to environmental cleanup programs.

The EPA’s Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities.  We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules.  Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

On August 20, 2010, the EPA published new regulations under the federal Clean Air Act (“CAA”) to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines.  The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment.  In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems.  If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations.  Compliance with the final rule is required by October 2013.

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.

XML

DEI Document	6 Months Ended
	Jun. 30, 2013	Aug. 02, 2013
Entity Information [Line Items]
Entity Registrant Name	Energy Transfer Equity, L.P.
Entity Central Index Key	0001276187
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		280,711,650

XML

Price Risk Management Assets And Liabilities

6 Months Ended

Jun. 30, 2013

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 our 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). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock 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 we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use 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 our derivative instruments using mark-to-market accounting, with changes in the fair value of our 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, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. We use 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.

We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use 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.

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

Derivatives are utilized in our midstream segment in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our 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:

	June 30, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	9,650,000	2013-2015	—		—
Basis Swaps IFERC/NYMEX (1)	(37,702,500)	2013-2014	(30,980,000	)	2013-2014
Power (Megawatt):
Forwards	145,078	2013	19,650		2013
Futures	(557,260)	2013	(1,509,300	)	2013
Options — Calls	(1,200)	2013	1,656,400		2013
Crude (Bbls) — Futures	(80,000)	2013	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	8,770,000	2013-2014	150,000		2013
Swing Swaps IFERC	20,060,000	2013	(83,292,500	)	2013
Fixed Swaps/Futures	23,435,000	2013-2015	27,077,500		2013
Forward Physical Contracts	1,758,402	2013-2014	11,689,855		2013-2014
Natural Gas Liquid (Bbls):
Forwards/Swaps	(597,000)	2013-2014	(30,000	)	2013
Refined Products (Bbls) — Futures	(1,227,000)	2013	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(10,530,000)	2013	(18,655,000	)	2013
Fixed Swaps/Futures	(32,682,500)	2013	(44,272,500	)	2013
Hedged Item — Inventory	32,682,500	2013	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(2,300,000)	2013	—		—
Fixed Swaps/Futures	(4,140,000)	2013	(8,212,500	)	2013
Natural Gas Liquid (Bbls):
Forwards/Swaps	(690,000)	2013	(930,000	)	2013
Crude (Bbls) — Futures	(210,000)	2013	—		—
Refined Products (Bbls) — Futures	—	—	(98,000	)	2013

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

We expect gains of $6 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:

	June 30, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	18,672,000	2013-2014	8,395,000	2013-2014
Propane (Gallons):
Forwards/Swaps	20,496,000	2013	3,318,000	2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	234,000	2013-2014	243,000	2013-2014
WTI Crude Oil (Barrels):
Forwards/Swaps	700,000	2013-2014	356,000	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. Southern Union also uses treasury rate locks to manage interest rate risk associated with long term borrowings.

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)	June 30, 2013		December 31, 2012
ETE	March 2017	Pay a fixed rate of 1.25% and receive a floating rate	$	500	$	500
ETP	July 2013 (2)	Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	100		400
ETP	July 2014 (2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate	400		400
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%	600		600
ETP	February 2023	Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%	400		—
Southern Union	November 2016	Pay a fixed rate of 2.91% and receive a floating rate	75		75
Southern Union	November 2021	Pay a fixed rate of 3.75% and receive a floating rate	450		450

⁽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.

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposures associated with a single or multiple counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry including petrochemical companies, consumer and industrials, oil and gas producers, municipalities, utilities and midstream companies. Our overall exposure to credit risk may be affected either positively or negatively in that the counterparties may experience similar changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

ETP utilizes master-netting agreements and has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about the settlement date for non-exchange traded derivatives. 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. ETP had net deposits with counterparties of $34 million and $41 million as of June 30, 2013 and December 31, 2012, respectively.

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 June 30, 2013 would be $13 million, which would be reduced by $1 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
	June 30, 2013		December 31, 2012		June 30, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	20	$	8	$	(2	)	$	(10	)
	20		8		(2		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	81	$	110	$	(80	)	$	(116	)
Commodity derivatives	91		40		(76		)	(44		)
Current assets held for sale	1		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		(5		)	(9		)
Interest rate derivatives	40		55		(122		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(47		)	(25		)
	213		207		(330		)	(429		)
Total derivatives	$	233	$	215	$	(332	)	$	(439	)

In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.

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
Contract Type	Balance Sheet Location	June 30, 2013			December 31, 2012			June 30, 2013			December 31, 2012
Bi-lateral contracts	Price risk management asset (liability)	$	82		$	28		$	(81	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	171			149			(155		)	(221		)
	Gross fair value	253			177			(236		)	(248		)
Collateral paid to OTC counterparties	Other current assets (liabilities)	—			—			—			2
Counterparty netting	Price risk management asset (liability)	(63		)	(25		)	63			25
Payments on margin deposit	Other current assets (liabilities)	(11		)	—			16			59
	Net fair value	179			152			(157		)	(162		)
	Other derivatives – gross	54			63			(175		)	(277		)
	Total derivatives	$	233		$	215		$	(332	)	$	(439	)

We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	6	$	(17	)	$	8	$	5
Interest rate derivatives	—		20			—		20
Total	$	6	$	3		$	8	$	25

	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 June 30,				Six Months Ended June 30,
		2013		2012		2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	1	$	13	$	2	$	16
Total		$	1	$	13	$	2	$	16

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,					Six Months Ended June 30,
		2013			2012		2013		2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(1	)	$	32	$	4	$	19
Total		$	(1	)	$	32	$	4	$	19

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2013			2012			2013			2012
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	3		$	—		$	(1	)	$	(11	)
Commodity derivatives — Non-Trading	Cost of products sold	35			12			14			12
Commodity derivatives — Non-Trading	Deferred gas purchases	2			—			(3		)	—
Interest rate derivatives	Gains (losses) on interest rate derivatives	46			(44		)	52			(17		)
Embedded derivatives	Other income	(8		)	8			(22		)	8
Total		$	78		$	(24	)	$	40		$	(8	)

XML

Unit-Based Compensation Plans (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
ETE Long-Term Incentive Plan [Member]
Remain unvested award	804,190
Unrecognized compensation expense	$ 42
Weighted average period for recognition, years	4 years 6 months 0 days
ETE Long-Term Incentive Plan [Member] | Employee [Member]
Granted unvested awards	750,000
ETE Long-Term Incentive Plan [Member] | Director [Member]
Granted unvested awards	6,042
ETP Unit-Based Compensation Plans [Member]
Granted unvested awards	1,074,163
Weighted average grant date fair value, per unit	$ 45.37
Remain unvested award	2,827,915
Unrecognized compensation expense	76
Weighted average period for recognition, years	1 year 9 months 0 days
ETP Unit-Based Compensation Plans [Member] | Director [Member]
Granted unvested awards	9,060
Regency Phantom Units [Member]
Vesting period (years)	5 years 0 months 0 days
Weighted average grant date fair value per unit option	$ 24.43
Remain unvested award	1,189,247
Granted awards	52,360
Unrecognized compensation expense	22
Weighted average period for recognition, years	5 years 0 months 0 days
Sunoco Logistics Unit-Based Compensation Plan [Member]
Remain unvested award	936,438
Unrecognized compensation expense	$ 19
Weighted average period for recognition, years	2 years 6 months 0 days
Director [Member]
Vesting period (years)	5 years 0 months 0 days
Minimum [Member] | Director [Member]
Vesting period (years)	3 years 0 months 0 days
Maximum [Member] | Director [Member]
Vesting period (years)	5 years 0 months 0 days

XML

Equity (IDR Schedule) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
2013 [Member]
IDR Subsidies	$ 42.00
2014 [Member]
IDR Subsidies	109.00
2015 [Member]
IDR Subsidies	53.00
2016 [Member]
IDR Subsidies	22.00
March 31 [Member] | 2014 [Member]
IDR Subsidies	27.25
March 31 [Member] | 2015 [Member]
IDR Subsidies	13.25
March 31 [Member] | 2016 [Member]
IDR Subsidies	5.50
June 30 [Member] | 2014 [Member]
IDR Subsidies	27.25
June 30 [Member] | 2015 [Member]
IDR Subsidies	13.25
June 30 [Member] | 2016 [Member]
IDR Subsidies	5.50
September 30 [Member] | 2013 [Member]
IDR Subsidies	21.00
September 30 [Member] | 2014 [Member]
IDR Subsidies	27.25
September 30 [Member] | 2015 [Member]
IDR Subsidies	13.25
September 30 [Member] | 2016 [Member]
IDR Subsidies	5.50
December 31 [Member] | 2013 [Member]
IDR Subsidies	21.00
December 31 [Member] | 2014 [Member]
IDR Subsidies	27.25
December 31 [Member] | 2015 [Member]
IDR Subsidies	13.25
December 31 [Member] | 2016 [Member]
IDR Subsidies	$ 5.50