10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 May 6, 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 – March 31, 2013 and December 31, 2012	1
Consolidated Statements of Operations – Three Months Ended March 31, 2013 and 2012	3
Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2013 and 2012	4
Consolidated Statement of Equity – Three Months Ended March 31, 2013	5
Consolidated Statements of Cash Flows – Three Months Ended March 31, 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	59
ITEM 4. CONTROLS AND PROCEDURES	62
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	62
ITEM 1A. RISK FACTORS	62
ITEM 6. EXHIBITS	63
SIGNATURE	64

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
Capacity	capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
Citrus	Citrus Corp., which owns 100% of FGT
Citrus Merger	ETP’s acquisition of Citrus Corp. on March 26, 2012
CrossCountry	CrossCountry Energy LLC
CRSA	Contingent Residual Support Agreement
ETC FEP	ETC Fayetteville Express Pipeline LLC
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, which owns a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula
GAAP	accounting principles generally accepted in the United States of America
HPC	RIGS Haynesville Partnership Co.

ii

Holdco	ETP Holdco Corporation
Holdco Transaction	October 5, 2012 transaction including contributions from ETP and ETE to Holdco
HOLP	Heritage Operating, L.P.
IDRs	incentive distribution rights
LIBOR	London Interbank Offered Rate
LNG Holdings	Trunkline LNG Holdings, LLC
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
Panhandle	Panhandle Eastern Pipe Line Company, LP and its subsidiaries
PEPL	Panhandle Eastern Pipe Line Company, LP
RIGS	Regency Intrastate Gas System
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 GP	Regency Energy Partners GP LP, the general partner of Regency
Regency LLC	Regency Energy Partners GP LLC, the general partner of Regency GP
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 Credit Facility	Southern Union’s revolving credit facility
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
Trunkline	Trunkline Gas Company, LLC
Trunkline LNG	Trunkline LNG Company, LLC
WTI	West Texas Intermediate Crude

iii

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.

iv

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	614		$	372
Accounts receivable, net	3,677			3,057
Accounts receivable from related companies	115			71
Inventories	1,659			1,522
Exchanges receivable	45			55
Price risk management assets	29			25
Current assets held for sale	136			184
Other current assets	352			311
Total current assets	6,627			5,597
PROPERTY, PLANT AND EQUIPMENT	31,026			30,388
ACCUMULATED DEPRECIATION	(2,386		)	(2,104		)
	28,640			28,284
NON-CURRENT ASSETS HELD FOR SALE	992			985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,708			4,737
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	36			43
GOODWILL	6,414			6,434
INTANGIBLE ASSETS, net	2,266			2,291
OTHER NON-CURRENT ASSETS, net	457			533
Total assets	$	50,140		$	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)

	March 31, 2013			December 31, 2012
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,573		$	3,107
Accounts payable to related companies	18			15
Exchanges payable	170			156
Price risk management liabilities	106			115
Accrued and other current liabilities	1,569			1,754
Current maturities of long-term debt	611			613
Current liabilities held for sale	80			85
Total current liabilities	6,127			5,845
NON-CURRENT LIABILTIES HELD FOR SALE	142			142
LONG-TERM DEBT, less current maturities	22,343			21,440
PREFERRED UNITS	340			331
DEFERRED INCOME TAXES	3,625			3,566
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	170			162
OTHER NON-CURRENT LIABILITIES	938			995
COMMITMENTS AND CONTINGENCIES (Note 14)
PREFERRED UNITS OF SUBSIDIARY	73			73
EQUITY:
General Partner	(1		)	—
Limited Partners:
Common Unitholders	2,047			2,125
Accumulated other comprehensive loss	(11		)	(12		)
Total partners’ capital	2,035			2,113
Noncontrolling interest	14,347			14,237
Total equity	16,382			16,350
Total liabilities and equity	$	50,140		$	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 March 31,
	2013			2012
REVENUES:
Natural gas sales	$	973		$	503
NGL sales	713			528
Crude sales	3,201			—
Gathering, transportation and other fees	740			489
Refined product sales	4,662			—
Other	890			150
Total revenues	11,179			1,670
COSTS AND EXPENSES:
Cost of products sold	9,807			1,015
Operating expenses	349			170
Depreciation and amortization	312			154
Selling, general and administrative	180			147
Total costs and expenses	10,648			1,486
OPERATING INCOME	531			184
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(310		)	(213		)
Bridge loan related fees	—			(62		)
Equity in earnings of unconsolidated affiliates	90			75
Gain on deconsolidation of Propane Business	—			1,056
Loss on extinguishment of debt	—			(115		)
Gains on interest rate derivatives	6			27
Other, net	(19		)	12
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	298			964
Income tax expense (benefit) from continuing operations	(2		)	2
INCOME FROM CONTINUING OPERATIONS	300			962
Income (loss) from discontinued operations	22			(1		)
NET INCOME	322			961
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	232			795
NET INCOME ATTRIBUTABLE TO PARTNERS	90			166
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	90		$	165
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.27		$	0.73
Diluted	$	0.27		$	0.73
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.32		$	0.73
Diluted	$	0.32		$	0.73

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 March 31,
	2013			2012
Net income	$	322		$	961
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	(1		)	—
Change in value of derivative instruments accounted for as cash flow hedges	2			22
Change in value of available-for-sale securities	1			—
Actuarial loss relating to pension and other postretirement benefits	(1		)	—
Foreign currency translation adjustment	(1		)	—
Change in other comprehensive income from equity investments	7			—
	7			22
Comprehensive income	329			983
Less: Comprehensive income attributable to noncontrolling interest	238			811
Comprehensive income attributable to partners	$	91		$	172

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

4

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 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		)	(178		)	—			—			(179		)
Distributions to noncontrolling interest	—			—			—			(333		)	(333		)
Subsidiary units issued for cash	—			10			—			182			192
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			—			14			14
Capital contributions from noncontrolling interest	—			—			—			11			11
Other, net	—			—			—			(2		)	(2		)
Other comprehensive income, net of tax	—			—			1			6			7
Net income	—			90			—			232			322
Balance, March 31, 2013	$	(1	)	$	2,047		$	(11	)	$	14,347		$	16,382

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

5

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)

	Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	322		$	961
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	312			154
Deferred income taxes	3			(2		)
Gain on curtailment of other postretirement benefit plans	—			(15		)
Amortization of finance costs charged to interest	(16		)	5
Bridge loan related fees	—			62
Non-cash compensation expense	16			12
Gain on deconsolidation of Propane Business	—			(1,056		)
Loss on extinguishment of debt	—			115
LIFO valuation adjustment	(38		)	—
Equity in earnings of unconsolidated affiliates	(90		)	(75		)
Distributions from unconsolidated affiliates	100			57
Other non-cash	17			11
Changes in operating assets and liabilities, net of effects of acquisitions and deconsolidation	(296		)	(150		)
Net cash provided by operating activities	330			79
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Southern Union Merger, net of cash received (Note 3)	—			(2,972		)
Cash paid for all other acquisitions, net of cash received	—			(10		)
Capital expenditures (excluding allowance for equity funds used during construction)	(761		)	(595		)
Contributions in aid of construction costs	8			6
Contributions to unconsolidated affiliates	(1		)	(15		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	30			19
Proceeds from the sale of assets	21			26
Cash proceeds from contribution of propane operations	—			1,384
Other	3			—
Net cash used in investing activities	(700		)	(2,157		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,899			4,787
Repayments of long-term debt	(1,961		)	(2,474		)
Subsidiary equity offerings, net of issue costs	192			385
Distributions to partners	(179		)	(140		)
Debt issuance costs	(16		)	(97		)
Distributions to noncontrolling interest	(333		)	(220		)
Capital contributions received from noncontrolling interest	11			5
Other, net	(1		)	(1		)
Net cash provided by financing activities	612			2,245
INCREASE IN CASH AND CASH EQUIVALENTS	242			167
CASH AND CASH EQUIVALENTS, beginning of period	372			126
CASH AND CASH EQUIVALENTS, end of period	$	614		$	293

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 amounts, except per unit data, are in millions)

(unaudited)

1. OPERATIONS AND ORGANIZATION:

Business Operations

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, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Southern Union, Sunoco, Sunoco Logistics and Holdco. 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”);

• Holdco which includes the operations of Southern Union and Sunoco; 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.

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.

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. Our 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. Our 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.

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

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

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

7

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

▪ ETC Compression, 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 directly owns Southern Union and Sunoco. As discussed in Note 3, 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 gathering, processing, transportation, storage and distribution of natural gas in the United States. As discussed in Note 3, 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:

•intrastate natural gas transportation and storage;

•interstate natural gas transportation and storage;

•midstream;

•NGL transportation and services;

•retail marketing;

•investment in Sunoco Logistics;

•investment in Regency; and

•corporate and other.

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 March 31, 2013 and for the three months ended March 31, 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. Management has evaluated subsequent events through the date the financial statements were issued.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of March 31, 2013, and the Partnership’s results of operations and cash flows for the three months endedMarch 31, 2013 and 2012. The unaudited interim consolidated financial statements

8

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.

2. ESTIMATES:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in goodwill impairment tests, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.

3. 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. On February 11, 2013, the Laclede Entities announced that it had 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. It is expected that the transactions contemplated by the Purchase and Sale Agreements are expected to close in the third quarter of 2013.

For the three months ended March 31, 2013 and the period from March 26, 2012 to March 31, 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 March 31, 2013 and December 31, 2012.

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency all of 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 Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $570 million in cash to Southern Union, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The total cash consideration was reduced by $107 million of estimated closing adjustments. 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 Contribution Agreement. 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 all distributions with respect to its IDRs on the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

9

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired from ETE its interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of estimated closing adjustments. ETE, which owns the general partner and IDRs of ETP, has agreed to forego all of the IDR payments 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 occurs, and 50% of the IDR payments on the newly issued ETP units for the following eight consecutive quarters. As a result, ETP now owns 100% of Holdco. As this transaction occurred subsequent to March 31, 2013, the Partnership’s consolidated historical results of operations, cash flows and financial position as of and for the quarter ended March 31, 2013 were not affected by this transaction.

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 in future periods.

4. INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

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

• AmeriGas. ETP owns approximately 30 million AmeriGas common units.

• 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 in Panola County, Mississippi.

• HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the RIGS, 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 March 31,
	2013		2012
Revenue	$	4,146	$	1,366
Operating income	349		314
Net income	230		215

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

5. 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:

	Three Months Ended March 31,
	2013		2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	434	$	245
Gain (loss) from subsidiary common unit transactions	$	10	$	(15	)
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	$	—	$	105

6. INVENTORIES:

Inventories consisted of the following:

	March 31, 2013		December 31, 2012
Natural gas and NGLs	$	227	$	338
Crude oil	644		418
Refined products	588		572
Appliances, parts and fittings and other	200		194
Total inventories	$	1,659	$	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.

11

7. FAIR VALUE MEASUREMENTS:

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.

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. At March 31, 2013 the fair value of the Preferred Units was based on the actual redemption value at 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 March 31, 2013 and December 31, 2012 was $24.86 billion and $24.15 billion, respectively. As of March 31, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $22.95 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.

12

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

	Fair Value Measurements  at March 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	51		$	—		$	51		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	7			7			—			—
Swing Swaps IFERC	1			—			1			—
Fixed Swaps/Futures	108			99			9			—
Forward Physical Contracts	1			—			1			—
NGLs — Forwards/Swaps	8			7			1			—
Power:
Forwards	3			—			3			—
Options — Calls	4			—			4			—
Refined Products — Futures	2			2			—			—
Total commodity derivatives	136			115			21			—
Total Assets	$	187		$	115		$	72		$	—
Liabilities:
Interest rate derivatives	$	(224	)	$	—		$	(224	)	$	—
Preferred Units	(340		)	—			—			(340		)
Embedded derivatives in the Regency Preferred Units	(39		)	—			—			(39		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(12		)	(12		)	—			—
Swing Swaps IFERC	(1		)	—			(1		)	—
Fixed Swaps/Futures	(116		)	(111		)	(5		)	—
Options — Calls	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(1		)	(1		)	—			—
Power:
Forwards	(1		)	—			(1		)	—
Futures	(1		)	(1		)	—			—
Options — Calls	(1		)	—			(1		)	—
Refined Products — Futures	(1		)	(1		)	—			—
Crude	(4		)	(4		)	—			—
Total commodity derivatives	(139		)	(130		)	(9		)	—
Total Liabilities	$	(742	)	$	(130	)	$	(233	)	$	(379	)

13

	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 three months ended March 31, 2013. There were no transfers between the fair value hierarchy levels during the three months ended March 31, 2013 or 2012.

Balance, December 31, 2012	$	(356	)
Net unrealized gain included in other income (expense)	(23		)
Balance, March 31, 2013	$	(379	)

14

8. NET INCOME PER LIMITED PARTNER UNIT:

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

	Three Months Ended March 31,
	2013		2012
Income from continuing operations	$	300	$	962
Less: Income from continuing operations attributable to noncontrolling interest	224		796
Income from continuing operations, net of noncontrolling interest	76		166
Less: General Partner’s interest in income from continuing operations	—		1
Income from continuing operations available to Limited Partners	$	76	$	165
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	279,959,091		226,730,477
Basic income from continuing operations per Limited Partner unit	$	0.27	$	0.73
Basic income from discontinued operations per Limited Partner unit	$	0.05	$	0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	76	$	165
Dilutive effect of equity-based compensation of subsidiaries	—		(1		)
Diluted income from continuing operations available to Limited Partners	$	76	$	164
Weighted average limited partner units	279,959,091		226,730,477
Diluted income from continuing operations per Limited Partner unit	$	0.27	$	0.73
Diluted income from discontinued operations per Limited Partner unit	$	0.05	$	0.00

The calculation above for the three months ended March 31, 2013 and 2012 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive.

9. DEBT OBLIGATIONS:

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.

In January 2013, Sunoco Logistics issued $350 million of 3.45% Senior Notes and $350 million of 4.95% Senior Notes (the “2023 and 2043 Senior Notes”), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under Sunoco Logistics’ existing senior notes. 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.

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. Regency will redeem all of its $162 million outstanding 2016 Senior Notes for cash equal to 104.688% of the principal amount, together with accrued and unpaid interest up to, but not including the redemption date.

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

15

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.

Revolving Credit Facilities

Parent Company Credit Facility

As of March 31, 2013, the Parent Company Credit Facility had a balance of $90 million outstanding and the amount available for future borrowings was $110 million. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 3.95%.

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 our current and future unsecured debt.

As of March 31, 2013, the ETP Credit Facility had a balance of $250 million outstanding and the amount available for future borrowings was $2.17 billion after taking into account letters of credit of $76 million. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 1.70%.

Regency Credit Facility

As of March 31, 2013, the Regency Credit Facility had a balance outstanding of $371 million in revolving credit loans and approximately $12 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2013, which was reduced by any letters of credit, was approximately $767 million, and the weighted average interest rate on the total amount outstanding as of March 31, 2013 was 3.02%.

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 March 31, 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 $33 million as of March 31, 2013.

Southern Union Credit Facilities

The Southern Union Credit Facility provides for borrowings of up to $700 million and expires in May 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. Outstanding borrowings under the Southern Union Credit Facility were $240 million as of March 31, 2013. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 1.83%.

In connection with the SUGS Contribution, borrowings under the Southern Union Credit Facility were repaid and the facility was terminated. 

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2013.

10. REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

On April 1, 2013, ETE completed the redemption (the “Redemption”) of all 3,000,000 of its 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. ETE paid $306 million in cash to GE Regency as consideration for the redeemed units, which represented principal and accrued and unpaid distributions payable thereon. 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

16

connection with a future redemption or conversion of the Preferred Units. At March 31, 2013 the fair value of the Preferred Units was based on the actual redemption value at April 1, 2013.

11. EQUITY:

ETE Common Units Issued

The change in ETE Common Units during the three months ended March 31, 2013 was as follows:

	Number of Units
Outstanding at December 31, 2012	279,955,608
Issuance of restricted units under equity incentive plans	6,042
Outstanding at March 31, 2013	279,961,650

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 three months ended March 31, 2013, we recognized increases in partners’ capital of $10 million.

Sales of Common Units by ETP

During the three months ended March 31, 2013, ETP received proceeds of $169 million, net of commissions of $2 million, from units issued pursuant to an Equity Distribution Agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated, which were used for general partnership purposes. ETP also received $29 million, net of commissions, in April 2013 from the settlement of transactions initiated in March 2013. No ETP Common Units remain available to be issued under this agreement.

For the three months ended March 31,2013, distributions of $23 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 0.5 million ETP Common Units. As of March 31, 2013, a total of 3.8 million ETP Common Units remain available to be issued under the existing registration statement.

On April 10, 2013, ETP issued 13.8 million ETP Common Units representing limited partner interests at $48.05 per ETP Common Unit in a public unit 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.

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

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

In conjunction with the 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 3, in connection with ETP’s acquisition of ETE’s

17

60% interest in Holdco on April 30, 2013, ETE also agreed to relinquish incentive distributions for the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred, and 50% of the incentive distributions for the following eight consecutive quarters on the newly issued ETP Common Units.

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	$	0.46
March 31, 2013	May 6, 2013	May 13, 2013	0.46

In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego all distributions with respect to its IDRs on 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	$	0.54500
March 31, 2013	May 9, 2013	May 15, 2013	0.57250

Accumulated Other Comprehensive Loss

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

	March 31, 2013			December 31, 2012
Net losses on commodity related hedges	$	(2	)	$	(3	)
Unrealized gains on available-for-sale securities	1			—
Foreign currency translation adjustment	(1		)	—
Actuarial loss related to pensions and other postretirement benefits	(11		)	(10		)
Equity investments, net	(2		)	(9		)
Subtotal	(15		)	(22		)
Amounts attributable to noncontrolling interest	4			10
Total accumulated other comprehensive loss, net of tax	$	(11	)	$	(12	)

12. 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 three months ended March 31, 2013, no awards were granted to ETE employees. As of March 31, 2013 a total of 54,190 unit awards remain unvested, including the new awards granted to ETE directors during the period. We expect to recognize a total of $1 million in compensation expense over a weighted average period of 1.6 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the three months ended March 31, 2013, ETP employees were granted a total of 1,064,413 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 $45.33 per unit. As of March 31, 2013 a total of 2,885,465 unit awards remain unvested, including the new awards granted during the period. ETP expects to

18

recognize a total of $88 million in compensation expense over a weighted average period of 1.9 years related to unvested awards.

Regency Unit-Based Compensation Plans

During the three months ended March 31, 2013, Regency employees and directors were granted 23,824 Regency phantom units with 5-year service vesting requirements. As of March 31, 2013, a total of 1,178,860 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $23.39 per unit. Regency expects to recognize a total of $23 million in compensation expense over a weighted average period of 5 years related to Regency’s unvested phantom units.

Sunoco Logistics Unit-Based Compensation Plan

As of March 31, 2013, a total of 964,465 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $23 million of expense over a weighted-average period of 2.6 years.

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 for the periods presented below:

	Three Months Ended March 31,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits		Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	2		$	—		$	—	$	—
Interest cost	9			2			—		—
Expected return on plan assets	(15		)	(3		)	—		—
Actuarial loss amortization	1			—			—		—
Settlement credits	(2		)	—			—		—
Curtailment recognition(2)	—			—			—		(15		)
	(5		)	(1		)	—		(15		)
Regulatory adjustment(3)	2			3			—		—
Net periodic benefit cost	$	(3	)	$	2		$	—	$	(15	)

⁽¹⁾  The three months ended March 31, 2012 includes 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.

19

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

Regulatory Matters

Southern Union and its Subsidiaries

The FERC is currently conducting an audit of PEPL, 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. The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.

Contingent Residual Support Agreement — AmeriGas

In January 2012, AmeriGas Finance LLC, a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% senior notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from AmeriGas Finance LLC through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes.

In connection with ETP’s contribution of its Propane Business, ETP entered into a CRSA with AmeriGas, AmeriGas Finance LLC, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt, as defined in the CRSA.

PEPL Holdings Guarantee of Collection

In accordance with the Contribution Agreement pursuant to which Southern Union contributed SUGS to Regency, 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, under the Contribution Agreement 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 the guarantee of collection 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.

NGL Pipeline Regulation

We have interests in NGL pipelines located in Texas. We believe that these pipelines do not provide interstate service and that they are thus not subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of our NGL facilities will remain unchanged; however, should they be found jurisdictional, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

Commitments

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled $33 million and $7 million for the three months endedMarch 31, 2013 and 2012, respectively, which include contingent rentals totaling $4 million for the three months ended March 31, 2013. During the three months ended March 31, 2013, $5 million 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 capital contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

20

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 is pending approval by the state court. A final approval hearing is set for June 26, 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.

21

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 December 31, 2012, 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 its 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 deadline for the remaining defendants to file an answer or otherwise respond was late April 2013. Trial in this action is not currently set.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of March 31, 2013 and December 31, 2012, accruals of approximately $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 March 31, 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).  In the event that Plaintiffs refuse Panhandle’s pending request

22

for voluntary dismissal, Panhandle will continue to vigorously defend the case.  Southern Union believes it has no liability associated with this proceeding.

Simmons v. Southern Union Company. Cause No. 1316-CV-07265, in the Circuit Court of Jackson County, Missouri, Kansas City:On March 22, 2013, the first lawsuit related to the February 19, 2013 natural gas incident at JJ's Restaurant was filed in Missouri state court on behalf of six injured restaurant employees. The defendants include Southern Union Company d/b/a MGE, USIC Locating Services, Inc. (the utility marking service), Heartland Midwest, LLC (the directional boring company and contractor of Time Warner Cable Media, Inc.), Time Warner Cable Media, Inc., Missouri One Call System, Inc., (Missouri's notification center for utility locates), and Mike Palier (MGE's first responder).  Plaintiffs' claims include negligence and strict liability for inherently dangerous activities. Plaintiffs have not specified an amount of damages, but seek punitive damages against MGE and certain other defendants in a jury trial. No trial date has been set.

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.  The hearing officer has stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices.  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.

23

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 March 31, 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.

	March 31, 2013		December 31, 2012
Current	$	41	$	46
Non-current	164		166
Total environmental liabilities	$	205	$	212

During the three months ended March 31, 2013, Sunoco recorded $7 million 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.

24

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.

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 hold 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.

25

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. Long-term physical contracts are tied to index prices.

26

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

	March 31, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX (1)	3,057,500	2013-2014	(30,980,000	)	2013-2014
Power (Megawatt):
Forwards	311,150	2013	19,650		2013
Futures	(452,400)	2013	(1,509,300	)	2013
Options — Calls	57,600	2013	1,656,400		2013
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,867,500)	2013-2014	150,000		2013
Swing Swaps IFERC	(11,755,000)	2013	(83,292,500	)	2013
Fixed Swaps/Futures	(6,065,000)	2013-2015	27,077,500		2013
Forward Physical Contracts	2,021,900	2013-2014	11,689,855		2013-2014
NGLs (Bbls):
Forwards/Swaps	(205,000)	2013	(30,000	)	2013
Crude (Bbls) — Futures	(120,000)	2013	—		—
Refined Products (Bbls) — Futures	1,772	2013-2014	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(6,960,000)	2013	(18,655,000	)	2013
Fixed Swaps/Futures	(7,260,000)	2013	(44,272,500	)	2013
Hedged Item — Inventory	7,260,000	2013	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,437,500)	2013	—		—
Fixed Swaps/Futures	(9,625,000)	2013	(8,212,500	)	2013
NGLs (Bbls):
Forwards/Swaps	(695,000)	2013	(930,000	)	2013
Crude (Bbls) — Futures	(270,000)	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 losses of $5 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 effected by the inherent volatility of these commodities, which could adversely effect its ability to make

27

distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.

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

	March 31, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	12,257,000	2013	8,395,000	2013-2014
Propane (Gallons):
Forwards/Swaps	1,722,000	2013	3,318,000	2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	188,000	2013-2014	243,000	2013-2014
WTI Crude Oil (Barrels):
Forwards/Swaps	422,000	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)	March 31, 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 4.02% and receive a floating rate	400		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 1.73% and receive a fixed rate of 3.60%	200		—
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

28

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 primarily of petrochemical companies and other industrial, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by 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 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 $23 million and $41 million as of March 31, 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.

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 sheets and recognized in net income or other comprehensive income.

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2013		December 31, 2012		March 31, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	4	$	8	$	(14	)	$	(10	)
	4		8		(14		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	120	$	110	$	(125	)	$	(116	)
Commodity derivatives	62		40		(56		)	(44		)
Current assets held for sale	8		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		(2		)	(9		)
Interest rate derivatives	51		55		(224		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(39		)	(25		)
	241		207		(446		)	(429		)
Total derivatives	$	245	$	215	$	(460	)	$	(439	)

In addition to the above derivatives, $1 million and $6 million in option premiums were included in price risk management assets and price risk management liabilities, respectively, as of March 31, 2013 are being amortized in 2013. In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.

29

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	March 31, 2013			December 31, 2012			March 31, 2013			December 31, 2012
Bi-lateral contracts	Price risk management asset (liability)	$	54		$	28		$	(52	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	183			149			(225		)	(221		)
	Gross fair value	237			177			(277		)	(248		)
Collateral paid to OTC counterparties	Other current assets (liabilities)	—			—			—			2
Counterparty netting	Price risk management asset (liability)	(51		)	(25		)	51			25
Payments on margin deposit	Other current assets (liabilities)	—			—			38			59
	Net fair value	$	186		$	152		$	(188	)	$	(162	)

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

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended March 31,
	2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	2	$	22
Total	$	2	$	22

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended March 31,
		2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	1	$	3
Total		$	1	$	3

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended March 31,
		2013		2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	5	$	(13	)
Total		$	5	$	(13	)

30

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2013			2012
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	(4	)	$	(11	)
Commodity derivatives — Non-Trading	Cost of products sold	(21		)	—
Commodity derivatives — Non-Trading	Deferred gas purchases	(5		)	—
Interest rate derivatives	Gains on interest rate derivatives	6			27
Embedded derivatives	Other income	(14		)	—
Total		$	(38	)	$	16

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 the 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).

31

17. OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:

	March 31, 2013		December 31, 2012
Deposits paid to vendors	$	23	$	41
Prepaid expenses and other	329		270
Total other current assets	$	352	$	311

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	March 31, 2013		December 31, 2012
Interest payable	$	372	$	334
Customer advances and deposits	54		61
Accrued capital expenditures	428		427
Accrued wages and benefits	136		250
Taxes payable other than income taxes	237		208
Income taxes payable	40		41
Deferred income taxes	86		130
Other	216		303
Total accrued and other current liabilities	$	1,569	$	1,754

18. REPORTABLE SEGMENTS:

As a result of the Holdco Transactions in October 2012, our reportable segments were re-evaluated and currently reflect eight reportable segments, which conduct their business exclusively in the United States of America, as follows:

•intrastate natural gas transportation and storage;

•interstate natural gas transportation and storage;

•midstream;

•NGL transportation and services;

•retail marketing;

•investment in Sunoco Logistics;

•investment in Regency; and

•corporate and other.

The amounts reflected as “Corporate and Other” include the Parent Company activity, the goodwill and property and plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. and certain operating segments that do not meet quantitative thresholds for separate reporting.

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.

32

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in Sunoco Logistics segment are primarily reflected in crude sales. Revenues from our Retail marketing segment are primarily reflected in refined product sales.

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.

	Three Months Ended March 31,
	2013			2012
Segment Adjusted EBITDA:
Intrastate Transportation and Storage	$	132		$	192
Interstate Transportation and Storage	297			80
Midstream	79			89
NGL Transportation and Services	80			50
Retail Marketing	37			—
Investment in Sunoco Logistics	236			—
Investment in Regency	127			134
Corporate and Other	64			36
Total	1,052			581
Depreciation and amortization	(312		)	(154		)
Interest expense, net of interest capitalized	(310		)	(213		)
Bridge loan related fees	—			(62		)
Gain on deconsolidation of Propane Business	—			1,056
Gains on interest rate derivatives	6			27
Non-cash unit-based compensation expense	(16		)	(12		)
Unrealized gains (losses) on commodity risk management activities	1			(84		)
Losses on extinguishment of debt	—			(115		)
Gain on curtailment of other postretirement benefit plans	—			15
LIFO valuation adjustment	38			—
Equity in earnings of unconsolidated affiliates	90			75
Adjusted EBITDA related to unconsolidated affiliates	(204		)	(141		)
Adjusted EBITDA related to discontinued operations	(40		)	(7		)
Other, net	(7		)	(2		)
Income from continuing operations before income tax expense	$	298		$	964

33

	March 31, 2013			December 31, 2012
Total assets:
Intrastate Transportation and Storage	$	4,579		$	4,691
Interstate Transportation and Storage	11,749			11,794
Midstream	4,989			5,098
NGL Transportation and Services	3,904			3,765
Retail Marketing	4,039			3,926
Investment in Sunoco Logistics	10,993			10,291
Investment in Regency	6,273			6,157
Corporate and Other	4,964			4,372
Adjustments and Eliminations	(1,350		)	(1,190		)
Total	$	50,140		$	48,904

34

	Three Months Ended March 31,
	2013			2012
Revenues:
Intrastate Transportation and Storage:
Revenues from external customers	$	650		$	446
Intersegment revenues	40			36
	690			482
Interstate Transportation and Storage:
Revenues from external customers	323			142
Intersegment revenues	1			—
	324			142
Midstream:
Revenues from external customers	750			459
Intersegment revenues	201			104
	951			563
NGL Transportation and Services:
Revenues from external customers	344			154
Intersegment revenues	21			13
	365			167
Retail Marketing:
Revenues from external customers	5,217			—
Intersegment revenues	5			—
	5,222			—
Investment in Sunoco Logistics:
Revenues from external customers	3,457			—
Intersegment revenues	55			—
	3,512			—
Investment in Regency:
Revenues from external customers	344			354
Intersegment revenues	5			4
	349			358
Corporate and Other:
Revenues from external customers	96			115
Intersegment revenues	54			14
	150			129
Adjustments and Eliminations:	(384		)	(171		)
Total revenues	$	11,179		$	1,670

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)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	42		$	9
Accounts receivable from related companies	4			11
Other current assets	45			3
Total current assets	91			23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,016			6,094
INTANGIBLE ASSETS, net	18			19
GOODWILL	9			9
NOTE RECEIVABLE FROM AFFILIATE	166			166
OTHER NON-CURRENT ASSETS, net	53			56
Total assets	$	6,353		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	1		$	1
Accounts payable to related companies	7			15
Interest payable	81			48
Price risk management liabilities	5			5
Accrued and other current liabilities	1			1
Current maturities of long-term debt	4			4
Total current liabilities	99			74
LONG-TERM DEBT, less current maturities	3,871			3,840
PREFERRED UNITS	340			331
OTHER NON-CURRENT LIABILITIES	8			9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	—
Limited Partners	2,047			2,125
Accumulated other comprehensive loss	(11		)	(12		)
Total partners’ capital	2,035			2,113
Total liabilities and partners’ capital	$	6,353		$	6,367

36

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2013			2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(6	)	$	(31	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(64		)	(43		)
Bridge loan related fees	—			(62		)
Equity in earnings of affiliates	168			307
Other, net	(8		)	(5		)
INCOME BEFORE INCOME TAXES	90			166
Income tax expense	—			—
NET INCOME	90			166
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	90		$	165

37

STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2013			2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	182		$	146
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions	—			(1,558		)
Note receivable from affiliate	—			(221		)
Net cash used in investing activities	—			(1,779		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	95			1,960
Principal payments on debt	(65		)	(72		)
Distributions to partners	(179		)	(140		)
Debt issuance costs	—			(76		)
Net cash provided by (used in) financing activities	(149		)	1,672
DECREASE IN CASH AND CASH EQUIVALENTS	33			39
CASH AND CASH EQUIVALENTS, beginning of period	9			18
CASH AND CASH EQUIVALENTS, end of period	$	42		$	57

38

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

AND RESULTS OF OPERATIONS

(Tabular dollar 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, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Southern Union, Sunoco, Sunoco Logistics and Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

OVERVIEW

We directly and indirectly own equity interests in entities that are engaged in diversified energy-related services. At March 31, 2013, our interests in ETP and Regency consisted of:

	General Partner Interest (as a % of total partnership  interest)		IDRs		Common Units
ETP	0.9	%	100	%	50,226,967
Regency	1.6	%	100	%	26,266,791

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.

Our reportable segments currently consist of the following:

• Reportable segments of ETP:

◦ Natural gas operations, including the following:

◦ natural gas midstream and intrastate transportation and storage through Southern Union and La Grange Acquisition, L.P., which conducts business under the assumed name of ETC OLP; and

◦ interstate natural gas transportation and storage through ET Interstate and Southern Union. ET Interstate is the parent company of Transwestern, ETC FEP, ETC Tiger and CrossCountry. Southern Union is the parent company of Panhandle, which provides transportation and storage services through the Panhandle, Trunkline and Sea Robin transmission systems.

◦ NGL transportation, storage and fractionation services primarily through Lone Star.

◦ Refined product and crude oil operations, including the following:

◦ refined product and crude oil transportation through Sunoco Logistics; and

◦ retail marketing of gasoline and middle distillates through Sunoco.

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

39

• Corporate and Other, including the following:

◦ activities of the Parent Company;

◦ 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.; and

◦ ETP’s corporate and other, which includes the following operating segments that do not meet the qualitative threshold for separate reporting:

▪ natural gas compression services through ETC Compression;

▪ a limited partner interest in AmeriGas;

▪ a non-operating interest in PES;

▪ natural gas distribution operations through Southern Union; and

▪ approximately 30% non-operating interest in a refining joint venture.

Each of the respective general partners of ETP and Regency have 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

Sale of Distribution Operations

In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., 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 is expected to be $1.04 billion, subject to customary closing adjustments, less the assumption of $19 million of debt. On February 11, 2013, The Laclede Group, Inc. announced that it had entered into an agreement with APUC that will allow a subsidiary of APUC to assume the right of The Laclede Group, Inc. to purchase the assets of Southern Union’s New England Gas Company division, subject to certain approvals. It is expected that the transactions contemplated by the purchase and sale agreement will close in the third quarter of 2013.

For the three months ended March 31, 2013 and the period from March 26, 2012 to March 31, 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 March 31, 2013 and December 31, 2012.

Crude Oil Joint Venture with Enbridge

On February 15, 2013, Enbridge Inc. (“Enbridge”) and ETP announced that we have entered into an agreement on the terms for the joint development of a project to provide crude oil pipeline access to the eastern Gulf Coast refinery market from the Patoka, Illinois hub. The project will involve the conversion from natural gas service to crude oil service of certain segments of pipeline that are currently in operation as part of the natural gas system of Trunkline, a subsidiary of ETP. This agreement is subject to approval by the FERC of Trunkline’s July 2012 request to abandon certain designated segments of pipeline from natural gas transmission service. The converted 30-inch diameter crude oil pipeline is expected to be in service by 2015. It will have capacity of up to 420,000 to 660,000 Bbls/d depending on crude slate and the level of subscriptions received in an open season to be conducted in the near future. Once completed, the project will span more than 700 miles, including a new lateral from central Louisiana, near the town of Boyce, to the refining market and the crude oil hub at St. James, Louisiana. The St. James hub will provide access to refineries in the eastern Gulf Coast, as well as dock access for water-borne shipments.

Enbridge and ETP would each own 50% of the joint venture entity. Enbridge’s participation in the venture is subject to a minimum level of commitments being obtained in the open season and on completion of due diligence.

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency all of 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 Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $570 million in cash to Southern Union, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The total cash consideration was reduced by $107 million of estimated closing adjustments. 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 Contribution Agreement. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive

40

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 all distributions with respect to its IDRs on the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired from ETE its interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of estimated closing adjustments. ETE, which owns the general partner and IDRs of ETP, has agreed to forego all of the IDR payments 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 occurs, and 50% of the IDR payments on the newly issued ETP units for the following eight consecutive quarters. As a result, ETP now owns 100% of Holdco. As this transaction occurred subsequent to March 31, 2013, the consolidated historical results of operations, cash flows and financial position as of and for the quarter ended March 31, 2013 were not affected by this transaction.

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.

41

Consolidated Results

	Three Months Ended March 31,
	2013			2012
Segment Adjusted EBITDA:
Intrastate Transportation and Storage	$	132		$	192
Interstate Transportation and Storage	297			80
Midstream	79			89
NGL Transportation and Services	80			50
Retail Marketing	37			—
Investment in Sunoco Logistics	236			—
Investment in Regency	127			134
Corporate and Other	64			36
Total	1,052			581
Depreciation and amortization	(312		)	(154		)
Interest expense, net of interest capitalized	(310		)	(213		)
Bridge loan related fees	—			(62		)
Gain on deconsolidation of Propane Business	—			1,056
Gains on interest rate derivatives	6			27
Non-cash unit-based compensation expense	(16		)	(12		)
Unrealized gains (losses) on commodity risk management activities	1			(84		)
Loss on extinguishment of debt	—			(115		)
Gain on curtailment of other postretirement benefit plans	—			15
LIFO valuation adjustment	38			—
Equity in earnings of unconsolidated affiliates	90			75
Adjusted EBITDA related to unconsolidated affiliates	(204		)	(141		)
Adjusted EBITDA related to discontinued operations	(40		)	(7		)
Other, net	(7		)	(2		)
Income from continuing operations before income tax expense	298			964
Income tax expense (benefit)	(2		)	2
Income from continuing operations	300			962
Income (loss) from discontinued operations	22			(1		)
Net income	$	322		$	961

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

Depreciation and Amortization. Depreciation and amortization increased primarily due to the following:

• depreciation and amortization related to Southern Union of $59 million for the three months ended March 31, 2013 compared to $4 million from March 26, 2012 to March 31, 2012;

• depreciation and amortization related to Sunoco Logistics and Sunoco of $64 million and $28 million, respectively, for the three months ended March 31, 2013; and

• additional depreciation and amortization recorded from assets placed in service.

Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:

• interest expense related to Southern Union of $33 million for the three months ended March 31, 2013 compared to $4 million from March 26, 2012 through March 31, 2012;

42

• interest expense of $19 million and $8 million recorded by Sunoco Logistics and Sunoco, respectively, for the three months ended March 31, 2013;

• incremental interest expense recorded by ETP primarily due to the issuance of $1.25 billion of Senior Notes in January 2013; and

• an increase of $21 million for the Parent Company primarily related to ETE’s senior secured term loan issued on March 26, 2012 to fund the Southern Union Merger; offset by

• a reduction of interest due to ETP’s repurchase of $750 million of its higher coupon senior notes in January 2012.

Bridge Loan Related Fees. The bridge loan commitment fee recognized during the three months ended March 31, 2012 was incurred in connection with the Southern Union Merger. The Parent Company obtained permanent financing for the transaction through a $2.0 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 were higher in the prior period due to an increase in forward rates during the three months ended March 31, 2012, which resulted in unrealized gains on our forward-starting floating-to-fixed swaps.

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.

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 for 2012 primarily include our proportionate share of such amounts related to AmeriGas, FEP, HPC, MEP and Citrus from March 26, 2012 to March 31, 2013. The 2013 amounts also include our proportionate share of such PES and Citrus.

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 decreased primarily due to deferred income taxes incurred in 2012 as a result of the gain on deconsolidation of ETP’s Propane Business.

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 Sunoco Merger and Holdco Transaction for the three months ended March 31, 2012, giving effect that each occurred on January 1, 2012. This unaudited pro forma financial 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 Sunoco Merger and Holdco Transaction had been consummated on January 1, 2012.

43

The following table presents the pro forma financial information for the three months ended March 31, 2012:

	ETE Historical			Propane Transaction			(a)	Sunoco Historical			(b)	Southern Union Historical			(c)	Holdco Pro Forma Adjustments			(d)	Pro Forma
REVENUES	$	1,670		$	(68	)		$	12,211			$	443			$	(4,620	)		$	9,636
COSTS AND EXPENSES:
Cost of products sold and natural gas operations	1,185			(55		)		11,491				313				(4,264		)		8,670
Depreciation and amortization	154			(2		)		61				49				26				288
Selling, general and administrative	147			(1		)		144				—				(25		)		265
Impairment charges	—			—				109				—				(35		)		74
Total costs and expenses	1,486			(58		)		11,805				362				(4,298		)		9,297
OPERATING INCOME	184			(10		)		406				81				(322		)		339
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(275		)	2				(47		)		(50		)		(20		)		(390		)
Equity in earnings of affiliates	75			4				3				16				(21		)		77
Gain on deconsolidation of Propane Business	1,056			(1,056		)		—				—				—				—
Gain on formation of Philadelphia Energy Solutions	—			2				104				—				—				106
Loss on extinguishment of debt	(115		)	115				—				—				—				—
Gains on interest rate derivatives	27			—				—				—				—				27
Other, net	12			—				3				(2		)		—				13
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	964			(943		)		469				45				(363		)		172
Income tax expense	2			—				170				12				(154		)		30
INCOME FROM CONTINUING OPERATIONS	$	962		$	(943	)		$	299			$	33			$	(209	)		$	142

(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.

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

44

• 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

Intrastate Transportation and Storage

	Three Months Ended March 31,
	2013			2012			Change
Natural gas transported (MMBtu/d)	9,733,480			10,114,354			(380,874		)
Revenues	$	690		$	482		$	208
Cost of products sold	496			314			182
Gross margin	194			168			26
Unrealized (gains) losses on commodity risk management activities	(12		)	82			(94		)
Operating expenses, excluding non-cash compensation expense	(39		)	(39		)	—
Selling, general and administrative expenses, excluding non-cash compensation expense	(11		)	(19		)	8
Segment Adjusted EBITDA	$	132		$	192		$	(60	)

Volumes. Transported volumes decreased due to the cessation of certain long-term contracts and lower volumes transported through our pipeline systems as a result of a continued unfavorable natural gas price environment.

Gross Margin. The components of our intrastate transportation and storage segment gross margin were as follows:

	Three Months Ended March 31,
	2013		2012			Change
Transportation fees	$	129	$	144		$	(15	)
Natural gas sales and other	27		14			13
Retained fuel revenues	23		17			6
Storage margin, including fees	15		(7		)	22
Total gross margin	$	194	$	168		$	26

Intrastate transportation and storage gross margin increased between the periods due to the net impact of the following:

• Transportation fees. Transportation fees decreased primarily due to lower volumes resulting from the cessation of certain long-term transportation contracts and lower volumes transported through our pipeline systems as a result of a continued unfavorable natural gas price environment.

From time to time, our marketing affiliate will contract with our intrastate pipelines for long-term and interruptible transportation capacity. Our intrastate transportation and storage segment recorded intercompany transportation fees from our marketing affiliate of $7 million during the three months ended March 31, 2013 and 2012.

• Natural gas sales and other. Margin from natural gas sales and other includes purchased natural gas for transport and sale, derivatives used to hedge transportation activities, and gains and losses on derivatives used to hedge net retained fuel. For the three months ended March 31, 2013 compared to the same period last year, margin from natural gas sales and other increased primarily due to an increase of $10 million in margin from system optimization activities and an increase of $2 million in margin from wellhead sales and purchases from the Eagle Ford Shale that were sold to end users on our HPL system. Excluding derivatives related to storage, unrealized gains of $1 million were recorded in the three months ended March 31, 2013 as compared to unrealized losses of $6 million in the same period last year.

• Retained fuel revenues. Retained fuel revenues include gross volumes retained as a fee at the current market price; the cost of consumed fuel is included in operating expenses. For the three months ended March 31, 2013 compared to the same period

45

last year, retention fuel revenue increased $6 million primarily due to an increase in the average of natural gas spot prices. The average spot price at the Houston Ship Channel for the three months ended March 31, 2013 increased to $3.43/MMBtu from $2.41/MMBtu in the same period last year. The increase in retained fuel revenues between the periods was attributable to an increase of $8 million due to price increases offset by a decrease of $2 million due to lower retention gas volumes.

Storage margin was comprised of the following:

	Three Months Ended March 31,
	2013			2012			Change
Withdrawals from storage natural gas inventory (MMBtu)	37,320,557			546,734			36,773,823
Realized margin (loss) on natural gas inventory transactions	$	(3	)	$	61		$	(64	)
Fair value inventory adjustments	20			(50		)	70
Unrealized losses on derivatives	(9		)	(26		)	17
Margin recognized on natural gas inventory and related derivatives	8			(15		)	23
Revenues from fee-based storage	7			8			(1		)
Total storage margin	$	15		$	(7	)	$	22

The increase in storage margin for the three months ended March 31, 2013 compared to the same period last year was principally driven by gains on the fair value adjustment of natural gas inventory held at our Bammel storage facility which was partially offset by an unfavorable variance from the settlement of derivatives used to hedge storage gas inventory. In the three months ended March 31, 2012, gains from the settlement of storage derivatives were realized with little physical offset due to the lack of withdrawals during the unusually warm winter season. Storage gas withdrawals resumed during the three months ended March 31, 2013, providing for greater parity between the margin realized on physical sales of storage gas and the loss on settlement of related storage derivatives.

Unrealized (Gains) Losses on Commodity Risk Management Activities. Unrealized gains and losses on commodity risk management activities reflect the net impact from unrealized gains and losses on storage and non-storage derivatives, as well as fair value adjustments to inventory. For the three months ended March 31, 2013, unrealized gains of $12 million included fair value adjustments to storage gas inventory of $20 million, partially offset by unrealized losses on derivatives of $8 million. For the three months ended March 31, 2012, unrealized losses of $82 million included unrealized losses on fair value adjustments to storage gas inventory of $50 million and unrealized losses on derivatives of $32 million. The unrealized losses for the three months ended March 31, 2012 reflected the impact of holding a larger volume of natural gas in our Bammel storage facility due to the warmer weather patterns noted above and were partially offset by settled financial derivative gains of $61 million.

Operating Expenses, Excluding Non-Cash Compensation Expense. Intrastate transportation and storage operating expenses reflected a $2 million decrease in pipeline maintenance offset by a $2 million increase in fuel consumption.

Selling, General and Administrative Expense, Excluding Non-Cash Compensation Expense. Intrastate transportation and storage selling, general and administrative expenses decreased primarily due to employee-related costs and allocated overhead expenses.

46

Interstate Transportation and Storage

	Three Months Ended March 31,
	2013			2012			Change
Natural gas transported (MMBtu/d):
ETP legacy assets	2,613,154			3,153,073			(539,919		)
Southern Union transportation and storage	4,420,650			3,764,599			656,051
Natural gas sold (MMBtu/d) – ETP legacy assets	16,768			20,517			(3,749		)
Revenues	$	324		$	142		$	182
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(72		)	(32		)	(40		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(35		)	(53		)	18
Adjusted EBITDA related to unconsolidated affiliates	80			23			57
Segment Adjusted EBITDA	$	297		$	80		$	217

Volumes. For the three months ended March 31, 2013 compared to the same period last year, the ETP legacy assets transported volumes decreased on the Tiger pipeline due to declines in supply, and transported volumes decreased on the Transwestern pipeline primarily due to lower basis differentials primarily on the eastern side of the pipeline. For the Southern Union assets, transported volumes increased on a daily average basis primarily due to colder weather along the Panhandle Eastern pipeline.

Revenues. Interstate transportation and storage revenues increased primarily due to the consolidation of Southern Union’s transportation and storage operations beginning March 26, 2012. The increase was offset slightly by a decrease in revenues of $3 million related to the Transwestern and Tiger pipelines.

Operating Expenses, Excluding Non-Cash Compensation, Amortization and Accretion Expenses. Substantially all of the increase in interstate transportation and storage operating expenses was due to the consolidation of Southern Union’s transportation and storage operations beginning March 26, 2012. The increase was offset slightly by a decrease in operating expenses of $4 million related to the Transwestern and Tiger pipelines.

Selling, General and Administrative Expense, Excluding Non-Cash Compensation, Amortization and Accretion Expenses. The variances in selling, general and administrative expenses were primarily due to the consolidation of Southern Union’s transportation and storage operations, beginning March 26, 2012, which resulted in incremental expenses of $27 million in the three months ended March 31, 2013. The impact of the incremental expenses in the current year was more than offset by Southern Union’s recognition of merger-related expenses during the period from March 26, 2012 to March 31, 2012. Selling, general and administrative expenses related to the Transwestern and Tiger pipelines decreased less than $1 million from the prior year.

Adjusted EBITDA Related to Unconsolidated Affiliates. Adjusted EBITDA related to unconsolidated affiliates increased for the three months ended March 31, 2013 compared to the same period last year primarily due to an increase of $58 million from Citrus, offset by a decrease of $1 million from FEP. We acquired a 50% interest in Citrus on March 26, 2012.

47

Midstream

	Three Months Ended March 31,
	2013			2012			Change
Gathered volumes (MMBtu/d):							—
ETP legacy assets	2,587,787			2,239,220			348,567
Southern Union gathering and processing	480,339			404,422			75,917
NGLs produced (Bbls/d)							—
ETP legacy assets	96,775			65,627			31,148
Southern Union gathering and processing	39,681			38,723			958
Equity NGLs produced (Bbls/d)							—
ETP legacy assets	9,499			17,630			(8,131		)
Southern Union gathering and processing	7,206			8,744			(1,538		)
Revenues	$	951		$	563		$	388
Cost of products sold	794			436			358
Gross margin	157			127			30
Unrealized losses on commodity risk management activities	—			2			(2		)
Operating expenses, excluding non-cash compensation expense	(49		)	(26		)	(23		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(29		)	(19		)	(10		)
Adjusted EBITDA related to discontinued operations	—			5			(5		)
Segment Adjusted EBITDA	$	79		$	89		$	(10	)

Volumes. NGL production increased primarily due to increased inlet volumes as a result of more production by our customers in the Eagle Ford Shale area. The decrease in equity NGL production was primarily due to processing plants optimizing NGL recoveries in response to the current NGL pricing environment.

Gross Margin. The components of our midstream segment gross margin were as follows:

	Three Months Ended March 31,
	2013			2012			Change
Gathering and processing fee-based revenues	$	97		$	70		$	27
Non fee-based contracts and processing	67			64			3
Other	(7		)	(7		)	—
Total gross margin	$	157		$	127		$	30

For the three months ended March 31, 2013 compared to the same period last year, midstream gross margin increased between the periods due to the net impact of the following:

• Gathering and processing fee-based revenues. Increased production in the Eagle Ford Shale resulted in increased fee-based revenues of $22 million. Additional volumes from the Woodford Shale also increased gross margin from our North Texas system by $3 million. The consolidation of Southern Union's gathering and processing segment also increased gross margin by $5 million. These increases were partially offset by a decline of $3 million on our Southeast Texas system as production shifted to the Eagle Ford Shale.

• Non fee-based contracts and processing. Our non fee-based gross margins increased $3 million primarily due to the consolidated of Southern Union’s gathering and processing segment, which contributed $22 million during the three months ended March 31, 2013. The composite NGL price decreased to $0.86 per gallon for the three months ended March 31, 2013 from $1.17 per gallon during the same period last year causing non fee-based margins to decrease by $19 million between the periods.

48

• Other midstream gross margin. Other midstream gross margin included fees charged by our intrastate transportation systems, which were recognized as income by our intrastate transportation and storage segment and eliminated in our consolidated results of operations.

Unrealized Losses on Commodity Risk Management Activities. Our midstream segment recorded unrealized losses associated with our marketing and NGL hedging activities of less than $1 million during the three months ended March 31, 2013 compared to unrealized losses of $2 million in the same period last year, mainly due to lower notional volumes hedged and price movements.

Operating Expenses, Excluding Non-Cash Compensation Expense. Substantially all of the increase in midstream operating expenses for the three months ended March 31, 2013 compared to the same period last year was due to the consolidation of Southern Union’s gathering and processing operations beginning March 26, 2012.

Selling, General and Administrative Expenses, Excluding Non-Cash Compensation Expense. Midstream selling, general and administrative expenses increased for the three months ended March 31, 2013 compared to the same period last year primarily due to the consolidation of Southern Union’s gathering and processing operations beginning March 26, 2012.

NGL Transportation and Services

	Three Months Ended March 31,
	2013			2012			Change
NGL transportation volumes (Bbls/d)	274,030			150,881			123,149
NGL fractionation volumes (Bbls/d)	86,703			20,006			66,697
Revenues	$	365		$	167		$	198
Cost of products sold	257			98			159
Gross margin	108			69			39
Operating expenses, excluding non-cash compensation expense	(19		)	(14		)	(5		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(10		)	(5		)	(5		)
Adjusted EBITDA related to unconsolidated affiliates	1			—			1
Segment Adjusted EBITDA	$	80		$	50		$	30

Volumes. NGL transportation volumes increased on our wholly-owned and joint venture NGL pipelines due to the completion of the Gateway and Justice pipelines in December 2012 and additional volumes from the startup of our Jackson and Kenedy processing plants in February 2013 and December 2012, respectively. Average daily fractionated volumes, including all physical and contractual volumes where we collected a fractionation fee, increased due to the commissioning of our fractionator at Mont Belvieu, Texas in December 2012.

Gross Margin. The components of our NGL transportation and services segment gross margin were as follows:

	Three Months Ended March 31,
	2013		2012		Change
Storage margin	$	32	$	32	$	—
Transportation fees	41		13		28
Processing and fractionation margin	34		24		10
Other margin	1		—		1
Total gross margin	$	108	$	69	$	39

NGL transportation and services segment gross margin increased between the periods due to the following:

• Transportation margin. Transportation margin increased due to an increase in volumes transported out of West Texas due to the commissioning of Lone Star’s Gateway pipeline during the fourth quarter of 2012. A higher concentration of volumes sourced from transportation contracts originating in West Texas and renegotiated contracts on the East side of the legacy Lone Star pipeline system increased our average realized rate. These volume and rate factors increases on our Lone Star pipeline system accounted for $21 million of the increase in transportation margin between the periods. The completion of our Justice

49

pipeline connection to Mont Belvieu, Texas and additional NGL production from our processing plants accounted for the remainder of the increase in transportation margin.

• Processing and fractionation margin. Processing and fractionation margin increased due to the startup of Lone Star’s fractionator at Mont Belvieu, Texas in December 2012, which contributed $16 million during the three months ended March 31, 2013. The increase in margin related to our fractionator was offset by a decrease in margin attributable to our fractionator in Geismar, Louisiana due to a less favorable pricing environment and contract mix.

• Other margin. Other margin included storage optimization and fractionator off-take agreements, for which there was no comparable activity in the same period last year.

Operating Expenses, Excluding Non-Cash Compensation Expense. NGL transportation and services operating expenses increased for the three months ended March 31, 2013 compared to the same period last year primarily due to increases in ad valorem taxes of $3 million and incremental expenses related to the start-up of Lone Star’s fractionator.

Selling, General and Administrative Expense, Excluding Non-Cash Compensation Expense. NGL transportation and services selling, general and administrative expenses increased for the three months ended March 31, 2013 compared to the same period last year primarily due to an increase in employee-related costs and allocated overhead expenses due to the overall asset growth on the system.

Investment in Sunoco Logistics

	Three Months Ended March 31,
	2013			2012		Change
Revenue	$	3,512		$	—	$	3,512
Cost of products sold	3,226			—		3,226
Gross margin	286			—		286
Unrealized gains on commodity risk management activities	(3		)	—		(3		)
Operating expenses, excluding non-cash compensation expense	(24		)	—		(24		)
Selling, general and administrative, excluding non-cash compensation expense	(30		)	—		(30		)
Adjusted EBITDA related to unconsolidated affiliates	7			—		7
Segment Adjusted EBITDA	$	236		$	—	$	236

We obtained control of Sunoco Logistics on October 5, 2012 in connection with our acquisition of Sunoco; therefore, no comparative results were reflected in our financial statements.

Retail Marketing

	Three Months Ended March 31,
	2013			2012		Change
Total retail gasoline outlets, end of period	4,979			—		4,979
Total company-operated outlets, end of period	439			—		439
Gasoline and diesel throughput per company-operated site (gallons/month)	187,000			—		187,000
Revenue	$	5,222		$	—	$	5,222
Cost of products sold	5,036			—		5,036
Gross margin	186			—		186
Operating expenses, excluding non-cash compensation expense	(98		)	—		(98		)
Selling, general and administrative, excluding non-cash compensation expense	(15		)	—		(15		)
LIFO valuation adjustment	(38		)	—		(38		)
Adjusted EBITDA related to unconsolidated affiliates	2			—		2
Segment Adjusted EBITDA	$	37		$	—	$	37

50

We acquired our retail marketing segment on October 5, 2012 in connection with our acquisition of Sunoco; therefore, no comparative results were reflected in our financial statements.

Investment in Regency

	Three Months Ended March 31,
	2013			2012			Change
Revenues	$	349		$	358		$	(9	)
Cost of products sold	229			240			(11		)
Gross margin	120			118			2
Unrealized losses (gains) on commodity risk management activities	18			(2		)	20
Operating expenses, excluding non-cash compensation expense	(45		)	(41		)	(4		)
Selling, general and administrative, excluding non-cash compensation expense	(15		)	(15		)	—
Adjusted EBITDA related to unconsolidated affiliates	63			57			6
Other	(14		)	17			(31		)
Segment Adjusted EBITDA	$	127		$	134		$	(7	)

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, excluding non-cash compensation expenses, increased primarily due to increase in employee expenses due to increased pipeline and plant operating activity in South and West Texas, increased compressor maintenance expense primarily due to increases in maintenance and materials costs, and increases in ad valorem taxes related to organic growth projects, partially offset by a decrease in contractor expense.

Adjusted EBITDA Related to Unconsolidated Affiliates. Regency's adjusted EBITDA attributable to unconsolidated affiliates increased primarily due to an $8 million increase in adjusted EBITDA attributable to Lone Star.

Other. Regency's other decreased primarily as the result of recognition of a $16 million one-time producer payment received in March 2012 related to an assignment of certain contracts in addition to a $14 million unrealized loss on the embedded derivative in Regency’s preferred units during the three months ended March 31, 2013.

All Other

	Three Months Ended March 31,
	2013			2012			Change
Revenue	$	150		$	129		$	21
Cost of products sold	137			91			46
Gross margin	13			38			(25		)
Unrealized (gains) losses on commodity risk management activities	(4		)	2			(6		)
Operating expenses, excluding non-cash compensation expense	(5		)	(20		)	15
Selling, general and administrative, excluding non-cash compensation expense	(25		)	(44		)	19
Adjusted EBITDA related to discontinued operations	40			2			38
Adjusted EBITDA related to unconsolidated affiliates	76			75			1
Eliminations	(31		)	(17		)	(14		)
Segment Adjusted EBITDA	$	64		$	36		$	28

51

Amounts reflected in our all other segment primarily include:

• Our retail propane and other retail propane related operations prior to our contribution of those operations to AmeriGas in January 2012. Our investment in AmeriGas was reflected in the all other segment subsequent to that transaction;

• Southern Union’s local distribution operations beginning March 26, 2012;

• Our natural gas compression operations;

• An approximate 30% non-operating interest in PES, a refining joint venture, effective upon our acquisition of Sunoco on October 5, 2012; and

• Activities of the Parent Company.

The decrease in gross margin and operating expenses was primarily due to our recognition of $31 million of gross margin and $18 million of operating expenses from our retail propane operations prior to the deconsolidation of those operations in January 2012. We also recognized $1 million of selling, general and administrative expenses from our retail propane operations prior to the deconsolidation in January 2012; however, the impact from the deconsolidation was more than offset by the recognition of additional selling, general and administrative expenses related to Sunoco in the three months ended March 31, 2013.

Adjusted EBITDA related to discontinued operations reflected the results of Southern Union's local distribution operations. Adjusted EBITDA related to unconsolidated affiliates reflected the results from our investments in AmeriGas and PES. Additional information related to unconsolidated affiliates is provided above in “Supplemental Information on Unconsolidated Affiliates.”

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.

52

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 the following capital expenditures for the remainder of 2013:

	Growth				Maintenance(2)
	Low		High		Low		High
Growth capital expenditures:
ETP legacy assets:
Midstream and intrastate transportation and storage	$	200	$	240	$	65	$	75
NGL transportation and services(1)	440		500		10		20
Interstate transportation and storage	10		20		15		25
	650		760		90		120
Holdco:
Southern Union transportation and storage	30		40		90		100
Retail marketing	20		50		55		65
	50		90		145		165
Investment in Sunoco Logistics	500		600		55		65
Total projected capital expenditures	$	1,200	$	1,450	$	290	$	350

⁽¹⁾  ETP expects to receive capital contributions from Regency related to their 30% share of Lone Star of $100 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 $684 million in growth capital expenditures, of which $409 million is expected to be invested in organic growth projects in the gathering and processing operations; $130 million is expected to be invested in Regency’s portion of growth capital expenditures in its NGL services segment; and $145 million is expected to be invested in growth capital expenditures in its contract services segment. In addition, Regency expects to invest $44 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.

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

53

services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of acquisitions and other factors.

Operating Activities

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

Three Months Ended March 31,2013 Compared to Three Months Ended March 31,2012. Cash provided by operating activities during 2013 was $330 million as compared to $79 million for 2012. Net income was $322 million and $961 million 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 $204 million and $789 million and changes in operating assets and liabilities of $296 million and $150 million for 2013 and 2012, respectively.

The non-cash activity in 2013 consisted primarily of depreciation and amortization of $312 million compared to $154 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 $115 million, and bridge loan related fees of $62 million which were not reflected in 2013.

Cash paid for interest, net of interest capitalized, was $291 million and $168 million for the three months endedMarch 31, 2013 and 2012, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from 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.

Three Months Ended March 31,2013 Compared to Three Months Ended March 31,2012. Cash used in investing activities during 2013 was $700 million as compared to $2.16 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 $761 million, including changes in accruals of $108 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2012 of $595 million, including changes in accruals of $53 million. In 2012, ETP also received cash proceeds from its contribution and sale of propane operations of $1.38 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.

Three Months Ended March 31,2013 Compared to Three Months Ended March 31,2012. Cash provided by financing activities during 2013 was $612 million as compared to $2.25 billion for 2012. In 2013, ETP received $192 million in net proceeds from offerings of ETP Common Units as compared to $87 million in 2012. Regency also received $297 million in net proceeds from its issuances of Regency Common Units in 2012. During 2013, we had a consolidated net increase in our debt level of $938 million as compared to a net increase of $2.31 billion for 2012. We paid distributions of $179 million and $140 million to our partners in 2013 and in 2012, respectively.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

54

	March 31, 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	2,000			2,000
ETE Senior Secured Revolving Credit Facility	90			60
Subsidiary Indebtedness:
ETP	8,942			7,692
Transwestern	870			870
Regency	1,962			1,962
Southern Union	1,260			1,260
Panhandle	1,621			1,621
Sunoco	965			965
Sunoco Logistics	2,150			1,450
Revolving Credit Facilities	894			1,936
Other Long-Term Debt	49			48
Unamortized premiums and fair value adjustments, net	351			389
Total	22,954			22,053
Current maturities	(611		)	(613		)
Long-term debt and notes payable, less current maturities	$	22,343		$	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 9 to our consolidated financial statements. As a result of the Southern Union Merger, we incurred additional indebtedness which is summarized below.

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 March 31, 2013, we had $90 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $110 million.

ETP Credit Facility

ETP has a $2.5 billion revolving 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 our current and future unsecured debt.

As of March 31, 2013, we had $250 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $2.17 billion after taking into account letters of credit of $76 million. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 1.70%.

Regency Credit Facility

As of March 31, 2013, there was a balance outstanding under the Regency Credit Facility of $371 million in revolving credit loans and approximately $12 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2013, which was reduced by any letters of credit, was approximately $767 million, and the weighted average interest rate on the total amount outstanding as of March 31, 2013 was 3.02%.

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 March 31, 2013.

55

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 $33 million as of March 31, 2013.

Southern Union Credit Facilities

The Southern Union Credit Facility provides for borrowings of up to $700 million and expires in May 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. Outstanding borrowings under the Southern Union Credit Facility were $240 million as of March 31, 2013. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 1.83%.

In connection with the SUGS Contribution, borrowings under the Southern Union Credit Facility were repaid and the facility was terminated.

Compliance with Our Covenants

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

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

	Three Months Ended March 31,
	2013		2012
Limited Partners	$	181	$	175
General Partner interest	—		—
Total Parent Company distributions	$	181	$	175

56

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:

	Three Months Ended March 31,
	2013		2012
Distributions from ETP:
Limited Partners (1)	$	45	$	47
General Partner interest	5		5
IDRs (2)	125		100
Total distributions from ETP (3)	175		152
Distributions from Regency:
Limited Partners	12		12
General Partner interest	1		1
IDRs	2		2
Total distributions from Regency	15		15
Total distributions received from subsidiaries	$	190	$	167

⁽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⁾  In conjunction with the Citrus Merger, ETE agreed to relinquish its rights to $220 million of distributions associated with the IDRs from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters. In addition, under the terms of the Holdco transaction agreement, ETE will relinquish an aggregate of $210 million of incentive distributions over 12 consecutive quarters following the closing of the Holdco Transaction. The distributions reflected above for the three months ended March 31,2013 and 2012 reflect IDR reductions totaling $31 million and $14 million, respectively, which includes one quarter of IDR relinquishment related to the Citrus Merger and one quarter related to the Holdco Transaction for 2013 and one quarter of IDR relinquishment related to the Citrus Merger for 2012.

⁽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.

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

57

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

	Three Months Ended March 31,
	2013		2012
Limited Partners:
Common Units	$	286	$	205
Class E Units	3		3
Class G Units	85		—
General Partner interest	5		5
IDRs	125		100
Total ETP distributions	$	504	$	313

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	$	0.46
March 31, 2013	May 6, 2013	May 13, 2013	0.46

The total amounts of Regency distributions declared and/or paid during the three months endedMarch 31, 2013 and 2012 were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

	Three Months Ended March 31,
	2013		2012
Limited Partners	$	79	$	78
General Partner interest	1		1
IDRs	2		2
Total Regency distributions	$	82	$	81

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

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

	Three Months Ended March 31, 2012
Limited Partners	$	59
General Partner interest	1
IDRs	25
Total Sunoco Logistics distributions	$	85

58

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.

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 March 31, 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.

59

ETP

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

	March 31, 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):
Basis Swaps IFERC/NYMEX (1)	3,057,500		$	(4	)	$	—	(30,980,000	)	$	(6	)	$	—
Power (Megawatt):
Forwards	311,150		2			1		19,650		—			1
Futures	(452,400	)	(1		)	—		(1,509,300	)	(1		)	1
Options — Calls	57,600		3			1		1,656,400		2			1
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,867,500	)	(1		)	—		150,000		(1		)	—
Swing Swaps IFERC	(11,755,000	)	—			—		(83,292,500	)	1			1
Fixed Swaps/Futures	(6,065,000	)	7			11		27,077,500		(7		)	9
Forward Physical Contracts	2,021,900		1			—		11,689,855		—			2
NGLs (Bbls) — Forwards/Swaps	(205,000	)	—			1		(30,000	)	—			—
Refined Products (Bbls) — Futures	1,772		1			35		(666,000	)	(3		)	14
Crude (Bbls) — Futures	(120,000	)	—			1		—		—			—
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(6,960,000	)	—			—		(18,655,000	)	(1		)	—
Fixed Swaps/Futures	(7,260,000	)	(4		)	3		(44,272,500	)	4			15
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,437,500	)	—			—		—		—			—
Fixed Swaps/Futures	(9,625,000	)	(7		)	4		(8,212,500	)	(3		)	3
NGLs (Bbls) — Forwards/Swaps	(695,000	)	3			4		(930,000	)	(2		)	7
Refined Products (Bbls) — Futures	—		—			—		(98,000	)	—			1
Crude (Bbls) — Futures	(270,000	)	(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.

60

Regency

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

	March 31, 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	12,257,000	$	(3	)	$	5	8,395,000	$	1	$	3
Propane:
Forwards/Swaps	1,722,000	—			—		3,318,000	1		1
NGLs:
Forwards/Swaps	188,000	1			1		243,000	—		2
WTI Crude Oil:
Forwards/Swaps	422,000	2			4		356,000	2		3

Interest Rate Risk

As of March 31, 2013, we and our subsidiaries had $4.05 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $40 million annually. We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements. To the extent that we have debt with floating interest rates that are not hedged, our results of operations, cash flows and financial condition could be adversely affected by increases in interest rates.

The following interest rate swaps were outstanding as of March 31, 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)	March 31, 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 4.02% and receive a floating rate	400		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 1.73% and receive a fixed rate of 3.60%	200		—
Southern Union	November 2021	Pay a fixed rate of 2.91% and receive a floating rate	75		75
Southern Union	November 2016	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 $97 million as of March 31, 2013 and $118 million as of December 31, 2012. For the $800 million of interest rate swaps whereby we pay a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $8 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect

61

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 primarily of petrochemical companies and other industrial, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by 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 March 31, 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

During the three months ended March 31, 2013, Southern Union’s accounting systems were transitioned to the accounting systems of ETP and ETE and accordingly certain controls changed at that time. None of these changes are in response to any identified deficiency or weakness in internal control over financial reporting.

There have been no other 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 March 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 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 March 31, 2013.

62

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.

ITEM 6. EXHIBITS

(a) Exhibits

The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.

	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
31.1			Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			Certification of President and 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			Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012; (ii) our Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012; (iii) our Consolidated Statements of Comprehensive Income for the three months ended March 31, 2013 and 2012; (iv) our Consolidated Statement of Equity for the three months ended March 31, 2013; (v) our Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012; and (vi) the notes to our Consolidated Financial Statements.

*    Incorporated herein by reference.

63

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:	May 9, 2013	By:	/s/ John W. McReynolds
			John W. McReynolds
			President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)

64

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: May 9, 2013

/s/ John W. McReynolds

John W. McReynolds

President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. McReynolds, President and Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

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

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

Date: May 9, 2013

/s/ John W. McReynolds

John W. McReynolds

President and 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

Operations And Organization (Schedule Of Equity Interests) (Details)	3 Months Ended
	Mar. 31, 2013
FEP [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
Citrus [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
Holdco [Member]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	60.00%
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

Debt Obligations (Southern Union Credit Facility) (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Southern Union Credit Facility [Member]
Line of Credit Facility [Line Items]
Amount Outstanding	$ 240
Weighted average interest rate on amount outstanding	1.83%
Southern Union [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 700

XML

Net Income Per Limited Partner Unit (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Reconciliation of income from continuing operations to income from continuing operations available to limited partners [Line Items]
Income from continuing operations	$ 300	$ 962
Income (Loss) from Continuing Operations Attributable to Noncontrolling Interest	224	796
Income from continuing operations, net of noncontrolling interest	76	166
Less: General Partner’s interest in income from continuing operations	0	1
Income from continuing operations available to Limited Partners	76	165
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average Limited Partner units	279,959,091	226,730,477
Basic income from continuing operations per Limited Partner unit	0.27	0.73
Basic income from discontinued operations per Limited Partner unit	$ 0.05	$ 0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Dilutive effect of equity-based compensation of subsidiaries	0	(1)
Diluted net income available to Limited Partners	$ 76	$ 164
Weighted average Limited Partner units	279,959,091	226,730,477
Diluted income from continuing operations per Limited Partner unit	0.27	0.73
Diluted income from discontinued operations per Limited Partner unit	$ 0.05	$ 0.00

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
	Mar. 31, 2013	Mar. 31, 2012
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	$ 1	$ 3
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	5	(13)
Amount of Gain/(Loss) Recognized in Income on Derivatives	(38)	16
Commodity Derivatives - Trading [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(4)	(11)
Commodity Derivatives [Member] | Cost of Products Sold [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	1	3
Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness	5	(13)
Amount of Gain/(Loss) Recognized in Income on Derivatives	(21)	0
Commodity Derivatives [Member] | Deferred Gas Purchases [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	(5)	0
Interest Rate Derivatives [Member] | Gains On Interest Rate Derivatives [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	6	27
Embedded Derivatives [Member] | Other Income (Expenses) [Member]
Amount of Gain/(Loss) Recognized in Income on Derivatives	$ (14)	$ 0

XML

Redeemable Preferred Units (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Preferred Units Redemption Amount	$ 306
Preferred Stock Redemption Premium	$ 40
ETE Preferred Units [Member]
Preferred Units, Outstanding	3,000,000

XML

Supplemental Financial Statement Information (Schedule Of Statements Of Cash Flows) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$ 330	$ 79
Cash paid for acquisitions	0	10
Net cash used in investing activities	(700)	(2,157)
Proceeds from borrowings	2,899	4,787
Repayments of long-term debt	(1,961)	(2,474)
Distributions to partners	(179)	(140)
Debt issuance costs	(16)	(97)
Net cash provided by (used in) financing activities	612	2,245
DECREASE IN CASH AND CASH EQUIVALENTS	242	167
CASH AND CASH EQUIVALENTS, beginning of period	372	126
CASH AND CASH EQUIVALENTS, end of period	614	293
Parent Company [Member]
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	182	146
Cash paid for acquisitions	0	(1,558)
Repayments of Related Party Debt	0	(221)
Net cash used in investing activities	0	(1,779)
Proceeds from borrowings	95	1,960
Repayments of long-term debt	(65)	(72)
Distributions to partners	(179)	(140)
Debt issuance costs	0	(76)
Net cash provided by (used in) financing activities	(149)	1,672
DECREASE IN CASH AND CASH EQUIVALENTS	33	39
CASH AND CASH EQUIVALENTS, beginning of period	9	18
CASH AND CASH EQUIVALENTS, end of period	$ 42	$ 57

XML

Fair Value Measurements (Fair Value Of Financial Assets And Liabilities Measured On Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Preferred Units	$ (340)	$ (331)
Fair Value, Measurements, Recurring [Member]
Interest rate derivatives, Asset Fair Value	51	55
Commodity derivatives, Asset Fair Value	136	156
Total Assets	187	211
Interest rate derivatives, Liability Fair Value	(224)	(235)
Preferred Units	(340)	(331)
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	(39)	(25)
Commodity derivatives, Liability Fair Value	(139)	(168)
Total Liabilities	(742)	(759)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Interest rate derivatives, Asset Fair Value	0	0
Commodity derivatives, Asset Fair Value	115	108
Total Assets	115	108
Interest rate derivatives, Liability Fair Value	0	0
Preferred Units	0	0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	(130)	(118)
Total Liabilities	(130)	(118)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Interest rate derivatives, Asset Fair Value	51	55
Commodity derivatives, Asset Fair Value	21	48
Total Assets	72	103
Interest rate derivatives, Liability Fair Value	(224)	(235)
Preferred Units	0	0
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	0	0
Commodity derivatives, Liability Fair Value	(9)	(50)
Total Liabilities	(233)	(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	(340)	(331)
Embedded derivatives in the Regency Preferred Units, Liability Fair Value	(39)	(25)
Commodity derivatives, Liability Fair Value	0	0
Total Liabilities	(379)	(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	2	5
Commodity derivatives, Liability Fair Value	(1)	(8)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	2	1
Commodity derivatives, Liability Fair Value	(1)	(1)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	0	4
Commodity derivatives, Liability Fair Value	0	(7)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Refined Products [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] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	3	27
Commodity derivatives, Liability Fair Value	(1)	(27)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value		1
Commodity derivatives, Liability Fair Value	(1)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	4	2
Commodity derivatives, Liability Fair Value	(1)
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		1
Commodity derivatives, Liability Fair Value	(1)	(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	3	27
Commodity derivatives, Liability Fair Value	(1)	(27)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Power [Member] | Level 2 [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 2 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value	4	2
Commodity derivatives, Liability Fair Value	(1)
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	7	11
Commodity derivatives, Liability Fair Value	(12)	(18)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Swing Swaps IFERC [Member]
Commodity derivatives, Asset Fair Value	1	3
Commodity derivatives, Liability Fair Value	(1)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	108	98
Commodity derivatives, Liability Fair Value	(116)	(103)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value		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
Commodity derivatives, Liability Fair Value		(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	7	11
Commodity derivatives, Liability Fair Value	(12)	(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	99	94
Commodity derivatives, Liability Fair Value	(111)	(94)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 1 [Member] | Call Option [Member]
Commodity derivatives, Asset Fair Value		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
Commodity derivatives, Liability Fair Value		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	1	3
Commodity derivatives, Liability Fair Value	(1)	(2)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - Natural Gas [Member] | Level 2 [Member] | Fixed Swaps/Futures [Member]
Commodity derivatives, Asset Fair Value	9	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		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
Commodity derivatives, Liability Fair Value		(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
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
Commodity derivatives, Liability Fair Value		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	8	2
Commodity derivatives, Liability Fair Value	(1)	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	7	1
Commodity derivatives, Liability Fair Value	(1)	(3)
Fair Value, Measurements, Recurring [Member] | Commodity Derivatives - NGLs [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Asset Fair Value	1	1
Commodity derivatives, Liability Fair Value	0	(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] | Commodity Contract [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Level 1 [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	(4)
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Level 2 [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	0
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Level 3 [Member] | Forward Swaps [Member]
Commodity derivatives, Liability Fair Value	$ 0

XML

Benefits (Tables)

3 Months Ended

Mar. 31, 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 for the periods presented below:

	Three Months Ended March 31,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits		Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	2		$	—		$	—	$	—
Interest cost	9			2			—		—
Expected return on plan assets	(15		)	(3		)	—		—
Actuarial loss amortization	1			—			—		—
Settlement credits	(2		)	—			—		—
Curtailment recognition(2)	—			—			—		(15		)
	(5		)	(1		)	—		(15		)
Regulatory adjustment(3)	2			3			—		—
Net periodic benefit cost	$	(3	)	$	2		$	—	$	(15	)

⁽¹⁾  The three months ended March 31, 2012 includes 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

Reportable Segments Operating Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 1,052	$ 581
Depreciation and amortization	(312)	(154)
Interest Expense, net of interest capitalized	(310)	(213)
Bridge loan related fees	0	(62)
Gain on deconsolidation of Propane Business	0	1,056
Gains on interest rate derivatives	6	27
Non-cash unit-based compensation expense	(16)	(12)
Unrealized Gain (Loss) on commodity risk management activities	1	(84)
Loss on extinguishment of debt	0	(115)
Gain on curtailment of other postretirement benefit plans	0	15
LIFO valuation adjustment	38	0
Equity in earnings of unconsolidated affiliates	90	75
Adjusted EBITDA related to unconsolidated affiliates	(204)	(141)
Adjusted EBITDA related to discontinued operations	(40)	(7)
Other than Temporary Impairment Losses, Investments	(7)	(2)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	298	964
ETP Intrastate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	132	192
ETP Interstate Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	297	80
ETP Midstream [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	79	89
ETP NGL Transportation and Services [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	80	50
ETP Retail Marketing [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	37	0
Investment in Sunoco Logistics [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	236	0
Investment In Regency [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	127	134
Corporate And Other Activities [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	$ 64	$ 36

XML

Equity (Change In ETE Common Units) (Details)	3 Months Ended
	Mar. 31, 2013
Partners' Capital Notes [Abstract]
Outstanding at December 31, 2012	279,955,608
Issuance of restricted units under equity incentive plans	6,042
Outstanding at March 31, 2013	279,961,650

XML

Supplemental Financial Statement Information (Schedule Of Balance Sheets) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2011
Cash and cash equivalents	$ 614	$ 372	$ 293	$ 126
Accounts receivable from related companies	115	71
Other current assets	352	311
Total current assets	6,627	5,597
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,708	4,737
INTANGIBLE ASSETS, net	2,266	2,291
GOODWILL	6,414	6,434
OTHER NON-CURRENT ASSETS, net	457	533
Total assets	50,140	48,904
Accounts payable	3,573	3,107
Accounts payable to related companies	18	15
Interest payable	372	334
Price risk management liabilities	106	115
Accrued and other current liabilities	1,569	1,754
Current maturities of long-term debt	611	613
Total current liabilities	6,127	5,845
LONG-TERM DEBT, less current maturities	22,343	21,440
PREFERRED UNITS OF SUBSIDIARY	73	73
OTHER NON-CURRENT LIABILITIES	938	995
COMMITMENTS AND CONTINGENCIES
General Partner	(1)	0
Limited Partners	2,047	2,125
Accumulated other comprehensive loss	(11)	(12)
Total partners’ capital	2,035	2,113
Total liabilities and equity	50,140	48,904
Parent Company [Member]
Cash and cash equivalents	42	9	57	18
Accounts receivable from related companies	4	11
Other current assets	45	3
Total current assets	91	23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,016	6,094
INTANGIBLE ASSETS, net	18	19
GOODWILL	9	9
Notes Receivable From Affiliate	166	166
OTHER NON-CURRENT ASSETS, net	53	56
Total assets	6,353	6,367
Accounts payable	1	1
Accounts payable to related companies	7	15
Interest payable	81	48
Price risk management liabilities	5	5
Accrued and other current liabilities	1	1
Current maturities of long-term debt	4	4
Total current liabilities	99	74
LONG-TERM DEBT, less current maturities	3,871	3,840
PREFERRED UNITS OF SUBSIDIARY	340	331
OTHER NON-CURRENT LIABILITIES	8	9
COMMITMENTS AND CONTINGENCIES
General Partner	(1)	0
Limited Partners	2,047	2,125
Accumulated other comprehensive loss	(11)	(12)
Total partners’ capital	2,035	2,113
Total liabilities and equity	$ 6,353	$ 6,367

XML

Supplemental Financial Statement Information (Schedule Of Statements Of Operations) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$ (180)	$ (147)
Interest expense	(310)	(213)
Gains on interest rate derivatives	6	27
Equity in earnings of unconsolidated affiliates	90	75
Other, net	(19)	12
Income tax expense (benefit)	(2)	2
NET INCOME ATTRIBUTABLE TO PARTNERS	90	166
GENERAL PARTNER’S INTEREST IN NET INCOME	0	1
LIMITED PARTNERS' INTEREST IN NET INCOME	90	165
Parent Company [Member]
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	(6)	(31)
Interest expense	(64)	(43)
Bridge loan related fees	0	(62)
Equity in earnings of unconsolidated affiliates	168	307
Other, net	(8)	(5)
INCOME BEFORE INCOME TAXES	90	166
Income tax expense (benefit)	0	0
NET INCOME ATTRIBUTABLE TO PARTNERS	90	166
GENERAL PARTNER’S INTEREST IN NET INCOME	0	1
LIMITED PARTNERS' INTEREST IN NET INCOME	$ 90	$ 165

XML

Other Information (Other Current Assets) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Other Information [Abstract]
Deposits paid to vendors	$ 23	$ 41
Prepaid expenses and other	329	270
Total other current assets	$ 352	$ 311

XML

Supplemental Financial Statement Information

3 Months Ended

Mar. 31, 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)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	42		$	9
Accounts receivable from related companies	4			11
Other current assets	45			3
Total current assets	91			23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,016			6,094
INTANGIBLE ASSETS, net	18			19
GOODWILL	9			9
NOTE RECEIVABLE FROM AFFILIATE	166			166
OTHER NON-CURRENT ASSETS, net	53			56
Total assets	$	6,353		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	1		$	1
Accounts payable to related companies	7			15
Interest payable	81			48
Price risk management liabilities	5			5
Accrued and other current liabilities	1			1
Current maturities of long-term debt	4			4
Total current liabilities	99			74
LONG-TERM DEBT, less current maturities	3,871			3,840
PREFERRED UNITS	340			331
OTHER NON-CURRENT LIABILITIES	8			9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	—
Limited Partners	2,047			2,125
Accumulated other comprehensive loss	(11		)	(12		)
Total partners’ capital	2,035			2,113
Total liabilities and partners’ capital	$	6,353		$	6,367

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2013			2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(6	)	$	(31	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(64		)	(43		)
Bridge loan related fees	—			(62		)
Equity in earnings of affiliates	168			307
Other, net	(8		)	(5		)
INCOME BEFORE INCOME TAXES	90			166
Income tax expense	—			—
NET INCOME	90			166
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	90		$	165

STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2013			2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	182		$	146
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions	—			(1,558		)
Note receivable from affiliate	—			(221		)
Net cash used in investing activities	—			(1,779		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	95			1,960
Principal payments on debt	(65		)	(72		)
Distributions to partners	(179		)	(140		)
Debt issuance costs	—			(76		)
Net cash provided by (used in) financing activities	(149		)	1,672
DECREASE IN CASH AND CASH EQUIVALENTS	33			39
CASH AND CASH EQUIVALENTS, beginning of period	9			18
CASH AND CASH EQUIVALENTS, end of period	$	42		$	57

XML

Debt Obligations (Parent Company) (Narrative) (Details) (USD $)	Mar. 31, 2013
Secured Debt	$ 2,000,000,000
ETE Senior Secured Revolving Credit Facilities [Member]
Outstanding borrowings	90,000,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 110,000,000
Debt, Weighted Average Interest Rate	3.95%
LIBOR [Member]
Debt Instrument, Basis Spread on Variable Rate	3.00%
Base Rate Loans [Member]
Debt Instrument, Basis Spread on Variable Rate	2.00%

XML

Investments in Affiliates Schedule of Equity Method Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Schedule of Equity Method Investments [Line Items]
Revenue	$ 4,146	$ 1,366
Operating income	349	314
Net income	$ 230	$ 215

XML

Reportable Segments Revenues (External and Intersegment) by Investments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues	$ 11,179	$ 1,670
ETP Intrastate Transportation and Storage [Member]
Revenue from External Customers	650	446
Intersegment Revenues	40	36
Segment Reporting Information, Revenue for Reportable Segment	690	482
ETP Interstate Transportation and Storage [Member]
Revenue from External Customers	323	142
Intersegment Revenues	1	0
Segment Reporting Information, Revenue for Reportable Segment	324	142
ETP Midstream [Member]
Revenue from External Customers	750	459
Intersegment Revenues	201	104
Segment Reporting Information, Revenue for Reportable Segment	951	563
ETP NGL Transportation and Services [Member]
Revenue from External Customers	344	154
Intersegment Revenues	21	13
Segment Reporting Information, Revenue for Reportable Segment	365	167
ETP Retail Marketing [Member]
Revenue from External Customers	5,217	0
Intersegment Revenues	5	0
Segment Reporting Information, Revenue for Reportable Segment	5,222	0
Investment in Sunoco Logistics [Member]
Revenue from External Customers	3,457	0
Intersegment Revenues	55	0
Segment Reporting Information, Revenue for Reportable Segment	3,512	0
Investment In Regency [Member]
Revenue from External Customers	344	354
Intersegment Revenues	5	4
Segment Reporting Information, Revenue for Reportable Segment	349	358
Corporate And Other Activities [Member]
Revenue from External Customers	96	115
Intersegment Revenues	54	14
Segment Reporting Information, Revenue for Reportable Segment	150	129
Adjustments And Eliminations [Member]
Revenue from External Customers	$ (384)	$ (171)

XML

Reportable Segments (Tables)

3 Months Ended

Mar. 31, 2013

Operating Segments [Member]

Financial Information By Segment

	Three Months Ended March 31,
	2013			2012
Segment Adjusted EBITDA:
Intrastate Transportation and Storage	$	132		$	192
Interstate Transportation and Storage	297			80
Midstream	79			89
NGL Transportation and Services	80			50
Retail Marketing	37			—
Investment in Sunoco Logistics	236			—
Investment in Regency	127			134
Corporate and Other	64			36
Total	1,052			581
Depreciation and amortization	(312		)	(154		)
Interest expense, net of interest capitalized	(310		)	(213		)
Bridge loan related fees	—			(62		)
Gain on deconsolidation of Propane Business	—			1,056
Gains on interest rate derivatives	6			27
Non-cash unit-based compensation expense	(16		)	(12		)
Unrealized gains (losses) on commodity risk management activities	1			(84		)
Losses on extinguishment of debt	—			(115		)
Gain on curtailment of other postretirement benefit plans	—			15
LIFO valuation adjustment	38			—
Equity in earnings of unconsolidated affiliates	90			75
Adjusted EBITDA related to unconsolidated affiliates	(204		)	(141		)
Adjusted EBITDA related to discontinued operations	(40		)	(7		)
Other, net	(7		)	(2		)
Income from continuing operations before income tax expense	$	298		$	964

Assets Segments [Member]

Financial Information By Segment

	March 31, 2013			December 31, 2012
Total assets:
Intrastate Transportation and Storage	$	4,579		$	4,691
Interstate Transportation and Storage	11,749			11,794
Midstream	4,989			5,098
NGL Transportation and Services	3,904			3,765
Retail Marketing	4,039			3,926
Investment in Sunoco Logistics	10,993			10,291
Investment in Regency	6,273			6,157
Corporate and Other	4,964			4,372
Adjustments and Eliminations	(1,350		)	(1,190		)
Total	$	50,140		$	48,904

Sales Revenue, Segment [Member]

Financial Information By Segment

	Three Months Ended March 31,
	2013			2012
Revenues:
Intrastate Transportation and Storage:
Revenues from external customers	$	650		$	446
Intersegment revenues	40			36
	690			482
Interstate Transportation and Storage:
Revenues from external customers	323			142
Intersegment revenues	1			—
	324			142
Midstream:
Revenues from external customers	750			459
Intersegment revenues	201			104
	951			563
NGL Transportation and Services:
Revenues from external customers	344			154
Intersegment revenues	21			13
	365			167
Retail Marketing:
Revenues from external customers	5,217			—
Intersegment revenues	5			—
	5,222			—
Investment in Sunoco Logistics:
Revenues from external customers	3,457			—
Intersegment revenues	55			—
	3,512			—
Investment in Regency:
Revenues from external customers	344			354
Intersegment revenues	5			4
	349			358
Corporate and Other:
Revenues from external customers	96			115
Intersegment revenues	54			14
	150			129
Adjustments and Eliminations:	(384		)	(171		)
Total revenues	$	11,179		$	1,670

XML

Debt Obligations (Regency Credit Facility) (Narrative) (Details) (Regency Credit Facility [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Regency Credit Facility [Member]
Outstanding borrowings	$ 371
Letters of Credit Outstanding, Amount	12
Amount available for future borrowings	$ 767
Weighted average interest rate on amount outstanding	3.02%

XML

Price Risk Management Assets And Liabilities (Fair Value Of Derivative Instruments) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Total derivatives assets	$ 245	$ 215
Total derivatives liabilities	(460)	(439)
Designated as Hedging Instrument [Member]
Total derivatives assets	4	8
Total derivatives liabilities	(14)	(10)
Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	4	8
Total derivatives liabilities	(14)	(10)
Not Designated as Hedging Instrument [Member]
Total derivatives assets	241	207
Total derivatives liabilities	(446)	(429)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives (Margin Deposits) [Member]
Total derivatives assets	120	110
Total derivatives liabilities	(125)	(116)
Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	62	40
Total derivatives liabilities	(56)	(44)
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member]
Total derivatives assets	51	55
Total derivatives liabilities	(224)	(235)
Not Designated as Hedging Instrument [Member] | Embedded Derivatives [Member]
Total derivatives assets	0	0
Total derivatives liabilities	(39)	(25)
Current Assets Held For Sale [Member] | Not Designated as Hedging Instrument [Member] | Commodity Derivatives [Member]
Total derivatives assets	8	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	$ (2)	$ (9)

XML

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

[1] (1) The three months ended March 31, 2012 includes 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

Fair Value Measurements (Reconciliation For Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Level 3 [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2012 Level 3 [Member] Fair Value, Measurements, Recurring [Member]
Fair Value, Measured on Recurring Basis, Gain (Loss) Included in Earnings	$ (23)
Balance, December 31, 2012		(379)	(356)
Balance, March 31, 2013		$ (379)	$ (356)

XML

Acquisitions

3 Months Ended

Mar. 31, 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. On February 11, 2013, the Laclede Entities announced that it had 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. It is expected that the transactions contemplated by the Purchase and Sale Agreements are expected to close in the third quarter of 2013.

For the three months ended March 31, 2013 and the period from March 26, 2012 to March 31, 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 March 31, 2013 and December 31, 2012.

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency all of 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 Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $570 million in cash to Southern Union, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The total cash consideration was reduced by $107 million of estimated closing adjustments. 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 Contribution Agreement. 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 all distributions with respect to its IDRs on the Regency common units issued in the transaction for the first eight consecutive quarters following the closing.

ETP’s Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired from ETE its interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of estimated closing adjustments. ETE, which owns the general partner and IDRs of ETP, has agreed to forego all of the IDR payments 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 occurs, and 50% of the IDR payments on the newly issued ETP units for the following eight consecutive quarters. As a result, ETP now owns 100% of Holdco. As this transaction occurred subsequent to March 31, 2013, the Partnership’s consolidated historical results of operations, cash flows and financial position as of and for the quarter ended March 31, 2013 were not affected by this transaction.

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 in future periods.

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Lease Expiration Date	Dec. 31, 2056
Operating Leases, Rent Expense	$ 33,000,000	$ 7,000,000
Operating Leases, Rent Expense, Contingent Rentals	4,000,000
Operating Leases, Income Statement, Sublease Revenue	5,000,000
Loss Contingency Accrual, at Carrying Value	42,000,000
Site Contingency, Number Of Sites Needing Remediation	39
Payments for Environmental Liabilities	7,000,000
Regency 4.50% Senior Notes Due 2023 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Guarantor Obligations, Current Carrying Value	600,000,000
Senior Notes Six Point Seven Five Due 2020 [Member] | AmeriGas Finance LLC [Member]
Debt Instrument, Face Amount	550,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.75%
Senior Notes Seven Point Zero Due 2022 [Member] | AmeriGas Finance LLC [Member]
Debt Instrument, Face Amount	1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	7.00%
AmeriGas [Member]
Proceeds from (Repayments of) Related Party Debt	1,500,000,000
State and Local Jurisdiction [Member]
Maximum Amount of Attorney's Fees	950,000
U.S Federal [Member]
Maximum Amount of Attorney's Fees	250,000
Attorney General of Commonwealth [Member]
Legal Fees	19,000,000
Percentage Of Recovery	50.00%
Reimbursement expert and consultant cost, maximum	$ 150,000

XML

Cash And Cash Equivalents (Schedule Of Non-Cash Investing & Financing Activities) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$ 434	$ 245
Gain (loss) from subsidiary common unit transactions	10	(15)
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	$ 105

XML

Inventories (Tables)

3 Months Ended

Mar. 31, 2013

Inventory, Net [Abstract]

Schedule Of Inventory

Inventories consisted of the following:

	March 31, 2013		December 31, 2012
Natural gas and NGLs	$	227	$	338
Crude oil	644		418
Refined products	588		572
Appliances, parts and fittings and other	200		194
Total inventories	$	1,659	$	1,522

XML

Cash And Cash Equivalents (Tables)

3 Months Ended

Mar. 31, 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:

	Three Months Ended March 31,
	2013		2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	434	$	245
Gain (loss) from subsidiary common unit transactions	$	10	$	(15	)
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	$	—	$	105

XML

Equity (Narrative) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Gain on Sale of Previously Unissued Stock by Subsidiary	$ 10	$ (15)
Partners' Capital Account, Units, Sold in Public Offering	13.8
Proceeds from issuance of common units	657
Equity Distribution Agreement Commissions	2
Price per Unit	$ 48.05
ETP [Domain]
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement	169
ETP [Member] | Distribution Reinvestment Plan [Member]
Value of units issued during period through DRIP	23
Units Issued During Period, Units, Distribution Reinvestment Plan	0.5
Equity Distribution Reinvestment Program, Capacity, Shares	3.8
Unit Settlements Subsequent to Quarter End [Member] | ETP [Member]
Proceeds From Issuance Of Common Limited Partners Units Under Equity Distribution Agreement	29
Citrus Merger [Member]
Relinquishment Of Rights Of Incentive Distributions	220
Number of periods of incentive distributions to be relinquished in future periods contingent upon closing of proposed transaction.	16
Holdco Transaction [Member]
Relinquishment Of Rights Of Incentive Distributions	$ 210
Number of periods of incentive distributions to be relinquished in future periods contingent upon closing of proposed transaction.	12

XML

Inventories (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Inventory, Net [Abstract]
Natural gas and NGLs	$ 227	$ 338
Crude oil	644	418
Refined products	588	572
Appliances, parts and fittings and other	200	194
Total inventories	$ 1,659	$ 1,522

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 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 March 31, 2013 and December 31, 2012 based on inputs used to derive their fair values:

	Fair Value Measurements  at March 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	51		$	—		$	51		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	7			7			—			—
Swing Swaps IFERC	1			—			1			—
Fixed Swaps/Futures	108			99			9			—
Forward Physical Contracts	1			—			1			—
NGLs — Forwards/Swaps	8			7			1			—
Power:
Forwards	3			—			3			—
Options — Calls	4			—			4			—
Refined Products — Futures	2			2			—			—
Total commodity derivatives	136			115			21			—
Total Assets	$	187		$	115		$	72		$	—
Liabilities:
Interest rate derivatives	$	(224	)	$	—		$	(224	)	$	—
Preferred Units	(340		)	—			—			(340		)
Embedded derivatives in the Regency Preferred Units	(39		)	—			—			(39		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(12		)	(12		)	—			—
Swing Swaps IFERC	(1		)	—			(1		)	—
Fixed Swaps/Futures	(116		)	(111		)	(5		)	—
Options — Calls	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(1		)	(1		)	—			—
Power:
Forwards	(1		)	—			(1		)	—
Futures	(1		)	(1		)	—			—
Options — Calls	(1		)	—			(1		)	—
Refined Products — Futures	(1		)	(1		)	—			—
Crude	(4		)	(4		)	—			—
Total commodity derivatives	(139		)	(130		)	(9		)	—
Total Liabilities	$	(742	)	$	(130	)	$	(233	)	$	(379	)

	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 three months ended March 31, 2013. There were no transfers between the fair value hierarchy levels during the three months ended March 31, 2013 or 2012.

Balance, December 31, 2012	$	(356	)
Net unrealized gain included in other income (expense)	(23		)
Balance, March 31, 2013	$	(379	)

XML

Net Income Per Limited Partner Unit (Tables)

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Reconciliation Of Net Income And Weighted Average Units

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

	Three Months Ended March 31,
	2013		2012
Income from continuing operations	$	300	$	962
Less: Income from continuing operations attributable to noncontrolling interest	224		796
Income from continuing operations, net of noncontrolling interest	76		166
Less: General Partner’s interest in income from continuing operations	—		1
Income from continuing operations available to Limited Partners	$	76	$	165
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	279,959,091		226,730,477
Basic income from continuing operations per Limited Partner unit	$	0.27	$	0.73
Basic income from discontinued operations per Limited Partner unit	$	0.05	$	0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	76	$	165
Dilutive effect of equity-based compensation of subsidiaries	—		(1		)
Diluted income from continuing operations available to Limited Partners	$	76	$	164
Weighted average limited partner units	279,959,091		226,730,477
Diluted income from continuing operations per Limited Partner unit	$	0.27	$	0.73
Diluted income from discontinued operations per Limited Partner unit	$	0.05	$	0.00

XML

Estimates and Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Estimates Disclosure [Abstract]

Estimates

ESTIMATES:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in goodwill impairment tests, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.

XML

Equity (Tables)

3 Months Ended

Mar. 31, 2013

Change In ETE Common Units

The change in ETE Common Units during the three months ended March 31, 2013 was as follows:

	Number of Units
Outstanding at December 31, 2012	279,955,608
Issuance of restricted units under equity incentive plans	6,042
Outstanding at March 31, 2013	279,961,650

Accumulated Other Comprehensive Income

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

	March 31, 2013			December 31, 2012
Net losses on commodity related hedges	$	(2	)	$	(3	)
Unrealized gains on available-for-sale securities	1			—
Foreign currency translation adjustment	(1		)	—
Actuarial loss related to pensions and other postretirement benefits	(11		)	(10		)
Equity investments, net	(2		)	(9		)
Subtotal	(15		)	(22		)
Amounts attributable to noncontrolling interest	4			10
Total accumulated other comprehensive loss, net of tax	$	(11	)	$	(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

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

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	$	0.46
March 31, 2013	May 6, 2013	May 13, 2013	0.46

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	$	0.54500
March 31, 2013	May 9, 2013	May 15, 2013	0.57250

XML

Acquisitions (Narrative) (Details) (USD $) Share data in Millions, unless otherwise specified			1 Months Ended				3 Months Ended
	Mar. 31, 2013	Oct. 05, 2012 Sunoco Merger [Member]	Feb. 28, 2013 SUGS Contribution [Member]	Mar. 21, 2013 Holdco Acquisition [Member]	Feb. 28, 2013 Southern Union [Member] SUGS Contribution [Member]	Feb. 28, 2013 ETP [Member] SUGS Contribution [Member]	Mar. 31, 2013 Holdco [Member]	Mar. 31, 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					570,000,000	30,000,000
Estimated Closing Adjustments				68,000,000		107,000,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest							60.00%	100.00%
Business Combination, Consideration Transferred		2,600,000,000
Business Acquisition Units Acquired		55.0		49.5
Business Acquisition, Cost of Acquired Entity, Cash Paid				$ 1,400,000,000

XML

Debt Obligations (Sunoco Logistics Credit Facilities) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 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	$ 33

XML

Other Information (Accrued And Other Current Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Other Information [Abstract]
Interest payable	$ 372	$ 334
Customer advances and deposits	54	61
Accrued capital expenditures	428	427
Accrued wages and benefits	136	250
Taxes payable other than income taxes	237	208
Income taxes payable	40	41
Deferred income taxes	86	130
Other	216	303
Total accrued and other current liabilities	$ 1,569	$ 1,754

XML

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
ASSETS
Cash and cash equivalents	$ 614	$ 372
Accounts receivable, net	3,677	3,057
Accounts receivable from related companies	115	71
Inventories	1,659	1,522
Exchanges receivable	45	55
Price risk management assets	29	25
Current assets held for sale	136	184
Other current assets	352	311
Total current assets	6,627	5,597
PROPERTY, PLANT AND EQUIPMENT	31,026	30,388
ACCUMULATED DEPRECIATION	(2,386)	(2,104)
PROPERTY, PLANT AND EQUIPMENT, net	28,640	28,284
NON-CURRENT ASSETS HELD FOR SALE	992	985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,708	4,737
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	36	43
GOODWILL	6,414	6,434
INTANGIBLE ASSETS, net	2,266	2,291
OTHER NON-CURRENT ASSETS, net	457	533
Total assets	50,140	48,904
LIABILITIES AND EQUITY
Accounts payable	3,573	3,107
Accounts payable to related companies	18	15
Exchanges payable	170	156
Price risk management liabilities	106	115
Accrued and other current liabilities	1,569	1,754
Current maturities of long-term debt	611	613
Current liabilities held for sale	80	85
Total current liabilities	6,127	5,845
NON-CURRENT LIABILTIES HELD FOR SALE	142	142
LONG-TERM DEBT, less current maturities	22,343	21,440
PREFERRED UNITS	340	331
DEFERRED INCOME TAXES	3,625	3,566
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	170	162
OTHER NON-CURRENT LIABILITIES	938	995
COMMITMENTS AND CONTINGENCIES (Note 14)
PREFERRED UNITS OF SUBSIDIARY	73	73
EQUITY:
General Partner	(1)	0
Limited Partners:
Common Unitholders	2,047	2,125
Accumulated other comprehensive loss	(11)	(12)
Total partners’ capital	2,035	2,113
Noncontrolling interest	14,347	14,237
Total equity	16,382	16,350
Total liabilities and equity	$ 50,140	$ 48,904

XML

Fair Value Measurements (Narrative) (Details) (USD $) In Billions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value Measurements [Abstract]
Debt obligations, fair value	$ 24.86	$ 24.15
Debt obligations, carrying amount	$ 22.95	$ 22.05

XML

Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 322	$ 961
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	312	154
Deferred income taxes	3	(2)
Gain on curtailment of other postretirement benefit plans	0	(15)
Amortization of finance costs charged to interest	(16)	5
Bridge loan related fees	0	62
Non-cash compensation expense	16	12
Gain on deconsolidation of Propane Business	0	(1,056)
Loss on extinguishment of debt	0	115
LIFO valuation adjustment	(38)	0
Equity in earnings of unconsolidated affiliates	(90)	(75)
Distributions from unconsolidated affiliates	100	57
Other non-cash	17	11
Changes in operating assets and liabilities, net of effects of acquisitions and deconsolidation	(296)	(150)
Net cash provided by operating activities	330	79
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions, net of cash received	0	(10)
Capital expenditures (excluding allowance for equity funds used during construction)	(761)	(595)
Contributions in aid of construction costs	8	6
Contributions to unconsolidated affiliates	(1)	(15)
Distributions from unconsolidated affiliates in excess of cumulative earnings	30	19
Proceeds from the sale of assets	21	26
Cash proceeds from contribution of propane operations	0	1,384
Other	3	0
Net cash used in investing activities	(700)	(2,157)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,899	4,787
Repayments of long-term debt	(1,961)	(2,474)
Subsidiary equity offerings, net of issue costs	192	385
Distributions to partners	(179)	(140)
Debt issuance costs	(16)	(97)
Distributions to noncontrolling interest	(333)	(220)
Capital contributions received from noncontrolling interest	11	5
Other, net	(1)	(1)
Net cash provided by financing activities	612	2,245
INCREASE IN CASH AND CASH EQUIVALENTS	242	167
CASH AND CASH EQUIVALENTS, beginning of period	372	126
CASH AND CASH EQUIVALENTS, end of period	614	293
Southern Union Merger [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for all other acquisitions, net of cash received	$ 0	$ (2,972)

XML

Equity (Accumulated Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Partners' Capital Notes [Abstract]
Unrealized gain (loss) on commodity contracts	$ (2)	$ (3)
Unrealized gains on available-for-sale securities	1	0
Foreign Currency Translation Adjustment	(1)	0
Actuarial loss related to pensions and other postretirement benefits	(11)	(10)
Equity investments, net	(2)	(9)
Accumulated other comprehensive income loss net of tax before non controlling interest	(15)	(22)
Amounts Attributable to Noncontrolling Interest	(4)	(10)
Accumulated other comprehensive loss	$ (11)	$ (12)

XML

Price Risk Management Assets And Liabilities (Tables)

3 Months Ended

Mar. 31, 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)	March 31, 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 4.02% and receive a floating rate	400		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 1.73% and receive a fixed rate of 3.60%	200		—
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
	March 31, 2013		December 31, 2012		March 31, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	4	$	8	$	(14	)	$	(10	)
	4		8		(14		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	120	$	110	$	(125	)	$	(116	)
Commodity derivatives	62		40		(56		)	(44		)
Current assets held for sale	8		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		(2		)	(9		)
Interest rate derivatives	51		55		(224		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(39		)	(25		)
	241		207		(446		)	(429		)
Total derivatives	$	245	$	215	$	(460	)	$	(439	)

In addition to the above derivatives, $1 million and $6 million in option premiums were included in price risk management assets and price risk management liabilities, respectively, as of March 31, 2013 are being amortized in 2013. 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	March 31, 2013			December 31, 2012			March 31, 2013			December 31, 2012
Bi-lateral contracts	Price risk management asset (liability)	$	54		$	28		$	(52	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	183			149			(225		)	(221		)
	Gross fair value	237			177			(277		)	(248		)
Collateral paid to OTC counterparties	Other current assets (liabilities)	—			—			—			2
Counterparty netting	Price risk management asset (liability)	(51		)	(25		)	51			25
Payments on margin deposit	Other current assets (liabilities)	—			—			38			59
	Net fair value	$	186		$	152		$	(188	)	$	(162	)

Partnership's Derivative Assets And Liabilities Recognized OCI On Derivatives

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended March 31,
	2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	2	$	22
Total	$	2	$	22

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 March 31,
		2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	1	$	3
Total		$	1	$	3

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended March 31,
		2013		2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	5	$	(13	)
Total		$	5	$	(13	)

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2013			2012
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	(4	)	$	(11	)
Commodity derivatives — Non-Trading	Cost of products sold	(21		)	—
Commodity derivatives — Non-Trading	Deferred gas purchases	(5		)	—
Interest rate derivatives	Gains on interest rate derivatives	6			27
Embedded derivatives	Other income	(14		)	—
Total		$	(38	)	$	16

ETP [Member]

Outstanding Commodity-Related Derivatives

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

	March 31, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX (1)	3,057,500	2013-2014	(30,980,000	)	2013-2014
Power (Megawatt):
Forwards	311,150	2013	19,650		2013
Futures	(452,400)	2013	(1,509,300	)	2013
Options — Calls	57,600	2013	1,656,400		2013
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,867,500)	2013-2014	150,000		2013
Swing Swaps IFERC	(11,755,000)	2013	(83,292,500	)	2013
Fixed Swaps/Futures	(6,065,000)	2013-2015	27,077,500		2013
Forward Physical Contracts	2,021,900	2013-2014	11,689,855		2013-2014
NGLs (Bbls):
Forwards/Swaps	(205,000)	2013	(30,000	)	2013
Crude (Bbls) — Futures	(120,000)	2013	—		—
Refined Products (Bbls) — Futures	1,772	2013-2014	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(6,960,000)	2013	(18,655,000	)	2013
Fixed Swaps/Futures	(7,260,000)	2013	(44,272,500	)	2013
Hedged Item — Inventory	7,260,000	2013	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,437,500)	2013	—		—
Fixed Swaps/Futures	(9,625,000)	2013	(8,212,500	)	2013
NGLs (Bbls):
Forwards/Swaps	(695,000)	2013	(930,000	)	2013
Crude (Bbls) — Futures	(270,000)	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:

	March 31, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	12,257,000	2013	8,395,000	2013-2014
Propane (Gallons):
Forwards/Swaps	1,722,000	2013	3,318,000	2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	188,000	2013-2014	243,000	2013-2014
WTI Crude Oil (Barrels):
Forwards/Swaps	422,000	2013-2014	356,000	2014

XML

Price Risk Management Assets And Liabilities (Outstanding Commodity-Related Derivatives) (Details)	Mar. 31, 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	3,057,500	[1]	(30,980,000)	[1]
Trading [Member] | Mark-To-Market Derivatives [Member] | Power [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(452,400)		(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	57,600		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	311,150		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] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
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	(1,867,500)		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	(11,755,000)		(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	(6,065,000)		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	12,257,000		8,395,000
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Natural Gas [Member] | Forward Physical Swaps [Member] | ETP [Member]
Notional Volume	2,021,900		11,689,855
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	(205,000)		(30,000)
Maximum Term Of Commodity Derivatives	2013		2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | NGL [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	188,000		243,000
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Crude Oil [Member] | Future [Member] | ETP [Member]
Notional Volume	(120,000)
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Propane [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	1,722,000		3,318,000
Maximum Term Of Commodity Derivatives	2013		2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Notional Volume	422,000		356,000
Maximum Term Of Commodity Derivatives			2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [Member]
Notional Volume	1,772		(666,000)
Maximum Term Of Commodity Derivatives			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
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] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014		2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Maximum [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	2014
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Maximum Term Of Commodity Derivatives	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
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] | Regency [Member]
Maximum Term Of Commodity Derivatives	2013		2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | WTI Crude Oil [Member] | Forwards Swaps [Member] | Regency [Member]
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Mark-To-Market Derivatives [Member] | Minimum [Member] | Refined Products [Member] | Forwards Swaps [Member] | ETP [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	(6,960,000)		(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	(7,260,000)		(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	7,260,000		44,272,500
Maximum Term Of Commodity Derivatives	2013		2013
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Basis Swaps IFERC/NYMEX [Member] | ETP [Member]
Notional Volume	(3,437,500)
Maximum Term Of Commodity Derivatives	2013
Non Trading [Member] | Cash Flow Hedging [Member] | Natural Gas [Member] | Fixed Swaps/Futures [Member] | ETP [Member]
Notional Volume	(9,625,000)		(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	(695,000)		(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	(270,000)
Maximum Term Of Commodity Derivatives	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

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

XML

Related Party Transactions

3 Months Ended

Mar. 31, 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 the 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

Other Information (Tables)

3 Months Ended

Mar. 31, 2013

Other Information [Abstract]

Other Current Assets

Other current assets consisted of the following:

	March 31, 2013		December 31, 2012
Deposits paid to vendors	$	23	$	41
Prepaid expenses and other	329		270
Total other current assets	$	352	$	311

Accrued And Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	March 31, 2013		December 31, 2012
Interest payable	$	372	$	334
Customer advances and deposits	54		61
Accrued capital expenditures	428		427
Accrued wages and benefits	136		250
Taxes payable other than income taxes	237		208
Income taxes payable	40		41
Deferred income taxes	86		130
Other	216		303
Total accrued and other current liabilities	$	1,569	$	1,754

XML

Reportable Segments

3 Months Ended

Mar. 31, 2013

Reportable Segments [Abstract]

Reportable Segments

REPORTABLE SEGMENTS:

As a result of the Holdco Transactions in October 2012, our reportable segments were re-evaluated and currently reflect eight reportable segments, which conduct their business exclusively in the United States of America, as follows:

•intrastate natural gas transportation and storage;

•interstate natural gas transportation and storage;

•midstream;

•NGL transportation and services;

•retail marketing;

•investment in Sunoco Logistics;

•investment in Regency; and

•corporate and other.

The amounts reflected as “Corporate and Other” include the Parent Company activity, the goodwill and property and plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. and certain operating segments that do not meet quantitative thresholds for separate reporting.

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.

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees. Revenues from our investment in Sunoco Logistics segment are primarily reflected in crude sales. Revenues from our Retail marketing segment are primarily reflected in refined product sales.

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.

	Three Months Ended March 31,
	2013			2012
Segment Adjusted EBITDA:
Intrastate Transportation and Storage	$	132		$	192
Interstate Transportation and Storage	297			80
Midstream	79			89
NGL Transportation and Services	80			50
Retail Marketing	37			—
Investment in Sunoco Logistics	236			—
Investment in Regency	127			134
Corporate and Other	64			36
Total	1,052			581
Depreciation and amortization	(312		)	(154		)
Interest expense, net of interest capitalized	(310		)	(213		)
Bridge loan related fees	—			(62		)
Gain on deconsolidation of Propane Business	—			1,056
Gains on interest rate derivatives	6			27
Non-cash unit-based compensation expense	(16		)	(12		)
Unrealized gains (losses) on commodity risk management activities	1			(84		)
Losses on extinguishment of debt	—			(115		)
Gain on curtailment of other postretirement benefit plans	—			15
LIFO valuation adjustment	38			—
Equity in earnings of unconsolidated affiliates	90			75
Adjusted EBITDA related to unconsolidated affiliates	(204		)	(141		)
Adjusted EBITDA related to discontinued operations	(40		)	(7		)
Other, net	(7		)	(2		)
Income from continuing operations before income tax expense	$	298		$	964

	March 31, 2013			December 31, 2012
Total assets:
Intrastate Transportation and Storage	$	4,579		$	4,691
Interstate Transportation and Storage	11,749			11,794
Midstream	4,989			5,098
NGL Transportation and Services	3,904			3,765
Retail Marketing	4,039			3,926
Investment in Sunoco Logistics	10,993			10,291
Investment in Regency	6,273			6,157
Corporate and Other	4,964			4,372
Adjustments and Eliminations	(1,350		)	(1,190		)
Total	$	50,140		$	48,904

	Three Months Ended March 31,
	2013			2012
Revenues:
Intrastate Transportation and Storage:
Revenues from external customers	$	650		$	446
Intersegment revenues	40			36
	690			482
Interstate Transportation and Storage:
Revenues from external customers	323			142
Intersegment revenues	1			—
	324			142
Midstream:
Revenues from external customers	750			459
Intersegment revenues	201			104
	951			563
NGL Transportation and Services:
Revenues from external customers	344			154
Intersegment revenues	21			13
	365			167
Retail Marketing:
Revenues from external customers	5,217			—
Intersegment revenues	5			—
	5,222			—
Investment in Sunoco Logistics:
Revenues from external customers	3,457			—
Intersegment revenues	55			—
	3,512			—
Investment in Regency:
Revenues from external customers	344			354
Intersegment revenues	5			4
	349			358
Corporate and Other:
Revenues from external customers	96			115
Intersegment revenues	54			14
	150			129
Adjustments and Eliminations:	(384		)	(171		)
Total revenues	$	11,179		$	1,670

XML

Price Risk Management Assets And Liabilities (Gross FV and Netting Offset) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 245	$ 215
Derivative Liability, Fair Value, Gross Liability	460	439
Netting [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	237	177
Derivative Liability, Fair Value, Gross Liability	(277)	(248)
Derivative Asset, Fair Value, Amount Offset Against Collateral	(51)	(25)
Derivative Liability, Fair Value, Amount Offset Against Collateral	51	25
Derivative Asset, Fair Value, Net	186	152
Derivative Liability, Fair Value, Net	(188)	(162)
Netting [Member] | Bi-lateral contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	54	28
Derivative Liability, Fair Value, Gross Liability	(52)	(27)
Netting [Member] | Broker cleared derivative contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	183	149
Derivative Liability, Fair Value, Gross Liability	(225)	(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	0	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	$ 38	$ 59

XML

Operations And Organization

3 Months Ended

Mar. 31, 2013

Operations And Organization [Abstract]

Operations And Organization

OPERATIONS AND ORGANIZATION:

Business Operations

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, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Southern Union, Sunoco, Sunoco Logistics and Holdco. 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”);

• Holdco which includes the operations of Southern Union and Sunoco; 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.

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.

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. Our 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. Our 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.

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

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

• ETC FEP, 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, 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, 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 directly owns Southern Union and Sunoco. As discussed in Note 3, 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 gathering, processing, transportation, storage and distribution of natural gas in the United States. As discussed in Note 3, 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:

•intrastate natural gas transportation and storage;

•interstate natural gas transportation and storage;

•midstream;

•NGL transportation and services;

•retail marketing;

•investment in Sunoco Logistics;

•investment in Regency; and

•corporate and other.

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 March 31, 2013 and for the three months ended March 31, 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. Management has evaluated subsequent events through the date the financial statements were issued.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of March 31, 2013, and the Partnership’s results of operations and cash flows for the three months endedMarch 31, 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.

XML

Consolidated Statements Of Operations (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
REVENUES:
Natural gas sales	$ 973	$ 503
NGL sales	713	528
Oil and Gas Sales Revenue	3,201	0
Gathering, transportation and other fees	740	489
Refining and Marketing Revenue	4,662	0
Other	890	150
Total revenues	11,179	1,670
COSTS AND EXPENSES:
Cost of products sold	9,807	1,015
Operating expenses	349	170
Depreciation and amortization	312	154
Selling, general and administrative	180	147
Total costs and expenses	10,648	1,486
OPERATING INCOME	531	184
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(310)	(213)
Bridge loan related fees	0	(62)
Equity in earnings of unconsolidated affiliates	90	75
Gain on deconsolidation of Propane Business	0	1,056
Loss on extinguishment of debt	0	(115)
Gains on interest rate derivatives	6	27
Other, net	(19)	12
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	298	964
Income tax expense (benefit) from continuing operations	(2)	2
INCOME FROM CONTINUING OPERATIONS	300	962
Income (loss) from discontinued operations	22	(1)
NET INCOME	322	961
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	232	795
NET INCOME ATTRIBUTABLE TO PARTNERS	90	166
GENERAL PARTNER’S INTEREST IN NET INCOME	0	1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$ 90	$ 165
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	0.27	0.73
Diluted	0.27	0.73
NET INCOME PER LIMITED PARTNER UNIT:
Basic	0.32	0.73
Diluted	0.32	0.73

XML

Equity

3 Months Ended

Mar. 31, 2013

Partners' Capital Notes [Abstract]

Equity

EQUITY:

ETE Common Units Issued

The change in ETE Common Units during the three months ended March 31, 2013 was as follows:

	Number of Units
Outstanding at December 31, 2012	279,955,608
Issuance of restricted units under equity incentive plans	6,042
Outstanding at March 31, 2013	279,961,650

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 three months ended March 31, 2013, we recognized increases in partners’ capital of $10 million.

Sales of Common Units by ETP

During the three months ended March 31, 2013, ETP received proceeds of $169 million, net of commissions of $2 million, from units issued pursuant to an Equity Distribution Agreement with Merrill Lynch, Pierce, Fenner & Smith Incorporated, which were used for general partnership purposes. ETP also received $29 million, net of commissions, in April 2013 from the settlement of transactions initiated in March 2013. No ETP Common Units remain available to be issued under this agreement.

For the three months ended March 31,2013, distributions of $23 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 0.5 million ETP Common Units. As of March 31, 2013, a total of 3.8 million ETP Common Units remain available to be issued under the existing registration statement.

On April 10, 2013, ETP issued 13.8 million ETP Common Units representing limited partner interests at $48.05 per ETP Common Unit in a public unit 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.

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

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

In conjunction with the 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 3, in connection with ETP’s acquisition of ETE’s 60% interest in Holdco on April 30, 2013, ETE also agreed to relinquish incentive distributions for the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred, and 50% of the incentive distributions for the following eight consecutive quarters on the newly issued ETP Common Units.

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	$	0.46
March 31, 2013	May 6, 2013	May 13, 2013	0.46

In conjunction with Southern Union’s contribution of SUGS to Regency, ETE agreed to forego all distributions with respect to its IDRs on 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	$	0.54500
March 31, 2013	May 9, 2013	May 15, 2013	0.57250

Accumulated Other Comprehensive Loss

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

	March 31, 2013			December 31, 2012
Net losses on commodity related hedges	$	(2	)	$	(3	)
Unrealized gains on available-for-sale securities	1			—
Foreign currency translation adjustment	(1		)	—
Actuarial loss related to pensions and other postretirement benefits	(11		)	(10		)
Equity investments, net	(2		)	(9		)
Subtotal	(15		)	(22		)
Amounts attributable to noncontrolling interest	4			10
Total accumulated other comprehensive loss, net of tax	$	(11	)	$	(12	)

XML

DEI Document	3 Months Ended
	Mar. 31, 2013	May 03, 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	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		280,711,650

XML

Unit-Based Compensation Plans

3 Months Ended

Mar. 31, 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 three months ended March 31, 2013, no awards were granted to ETE employees. As of March 31, 2013 a total of 54,190 unit awards remain unvested, including the new awards granted to ETE directors during the period. We expect to recognize a total of $1 million in compensation expense over a weighted average period of 1.6 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the three months ended March 31, 2013, ETP employees were granted a total of 1,064,413 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 $45.33 per unit. As of March 31, 2013 a total of 2,885,465 unit awards remain unvested, including the new awards granted during the period. ETP expects to recognize a total of $88 million in compensation expense over a weighted average period of 1.9 years related to unvested awards.

Regency Unit-Based Compensation Plans

During the three months ended March 31, 2013, Regency employees and directors were granted 23,824 Regency phantom units with 5-year service vesting requirements. As of March 31, 2013, a total of 1,178,860 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $23.39 per unit. Regency expects to recognize a total of $23 million in compensation expense over a weighted average period of 5 years related to Regency’s unvested phantom units.

Sunoco Logistics Unit-Based Compensation Plan

As of March 31, 2013, a total of 964,465 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $23 million of expense over a weighted-average period of 2.6 years.

XML

Consolidated Statements Of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement of Other Comprehensive Income [Abstract]
Net income	$ 322	$ 961
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	(1)	0
Change in value of derivative instruments accounted for as cash flow hedges	2	22
Change in value of available-for-sale securities	1	0
Actuarial loss relating to pension and other postretirement benefits	(1)	0
Foreign currency translation adjustment	(1)	0
Change in other comprehensive income from equity investments	7	0
Other comprehensive income (loss), net of tax	7	22
Comprehensive income	329	983
Less: Comprehensive income attributable to noncontrolling interest	238	811
Comprehensive income attributable to partners	$ 91	$ 172

XML

Inventories (Notes)

3 Months Ended

Mar. 31, 2013

Inventory, Net [Abstract]

Inventories

INVENTORIES:

Inventories consisted of the following:

	March 31, 2013		December 31, 2012
Natural gas and NGLs	$	227	$	338
Crude oil	644		418
Refined products	588		572
Appliances, parts and fittings and other	200		194
Total inventories	$	1,659	$	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

Cash And Cash Equivalents

3 Months Ended

Mar. 31, 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:

	Three Months Ended March 31,
	2013		2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	434	$	245
Gain (loss) from subsidiary common unit transactions	$	10	$	(15	)
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	$	—	$	105

XML

Other Information

3 Months Ended

Mar. 31, 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:

	March 31, 2013		December 31, 2012
Deposits paid to vendors	$	23	$	41
Prepaid expenses and other	329		270
Total other current assets	$	352	$	311

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	March 31, 2013		December 31, 2012
Interest payable	$	372	$	334
Customer advances and deposits	54		61
Accrued capital expenditures	428		427
Accrued wages and benefits	136		250
Taxes payable other than income taxes	237		208
Income taxes payable	40		41
Deferred income taxes	86		130
Other	216		303
Total accrued and other current liabilities	$	1,569	$	1,754

XML

Benefits

3 Months Ended

Mar. 31, 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 for the periods presented below:

	Three Months Ended March 31,
	2013						2012 (1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits		Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	2		$	—		$	—	$	—
Interest cost	9			2			—		—
Expected return on plan assets	(15		)	(3		)	—		—
Actuarial loss amortization	1			—			—		—
Settlement credits	(2		)	—			—		—
Curtailment recognition(2)	—			—			—		(15		)
	(5		)	(1		)	—		(15		)
Regulatory adjustment(3)	2			3			—		—
Net periodic benefit cost	$	(3	)	$	2		$	—	$	(15	)

⁽¹⁾  The three months ended March 31, 2012 includes 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

Debt Obligations

3 Months Ended

Mar. 31, 2013

Debt Obligations [Abstract]

Debt Obligations

DEBT OBLIGATIONS:

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.

In January 2013, Sunoco Logistics issued $350 million of 3.45% Senior Notes and $350 million of 4.95% Senior Notes (the “2023 and 2043 Senior Notes”), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under Sunoco Logistics’ existing senior notes. 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.

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. Regency will redeem all of its $162 million outstanding 2016 Senior Notes for cash equal to 104.688% of the principal amount, together with accrued and unpaid interest up to, but not including the redemption date.

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.

Revolving Credit Facilities

Parent Company Credit Facility

As of March 31, 2013, the Parent Company Credit Facility had a balance of $90 million outstanding and the amount available for future borrowings was $110 million. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 3.95%.

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 our current and future unsecured debt.

As of March 31, 2013, the ETP Credit Facility had a balance of $250 million outstanding and the amount available for future borrowings was $2.17 billion after taking into account letters of credit of $76 million. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 1.70%.

Regency Credit Facility

As of March 31, 2013, the Regency Credit Facility had a balance outstanding of $371 million in revolving credit loans and approximately $12 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2013, which was reduced by any letters of credit, was approximately $767 million, and the weighted average interest rate on the total amount outstanding as of March 31, 2013 was 3.02%.

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 March 31, 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 $33 million as of March 31, 2013.

Southern Union Credit Facilities

The Southern Union Credit Facility provides for borrowings of up to $700 million and expires in May 2016. Borrowings under the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. Outstanding borrowings under the Southern Union Credit Facility were $240 million as of March 31, 2013. The weighted average interest rate on the total amount outstanding as of March 31, 2013 was 1.83%.

In connection with the SUGS Contribution, borrowings under the Southern Union Credit Facility were repaid and the facility was terminated. 

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of March 31, 2013.

XML

Unit-Based Compensation Plans (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
ETE Long-Term Incentive Plan [Member]
Granted unvested awards	0
Remain unvested award	54,190
Unrecognized compensation expense	$ 1
Weighted average period for recognition, years	1 year 7 months 12 days
ETP Unit-Based Compensation Plans [Member]
Granted unvested awards	1,064,413
Weighted average grant date fair value, per unit	$ 45.33
Remain unvested award	2,885,465
Unrecognized compensation expense	88
Weighted average period for recognition, years	1 year 10 months 15 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	$ 23.39
Remain unvested award	1,178,860
Granted awards	23,824
Unrecognized compensation expense	23
Weighted average period for recognition, years	5 years 0 months 0 days
Sunoco Logistics Unit-Based Compensation Plan [Member]
Remain unvested award	964,465
Unrecognized compensation expense	$ 23
Weighted average period for recognition, years	2 years 7 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

Fair Value Measurements

3 Months Ended

Mar. 31, 2013

Fair Value Measurements [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS:

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.

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. At March 31, 2013 the fair value of the Preferred Units was based on the actual redemption value at 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 March 31, 2013 and December 31, 2012 was $24.86 billion and $24.15 billion, respectively. As of March 31, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $22.95 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 March 31, 2013 and December 31, 2012 based on inputs used to derive their fair values:

	Fair Value Measurements  at March 31, 2013
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	51		$	—		$	51		$	—
Commodity derivatives:
Condensate — Forward Swaps	2			—			2			—
Natural Gas:
Basis Swaps IFERC/NYMEX	7			7			—			—
Swing Swaps IFERC	1			—			1			—
Fixed Swaps/Futures	108			99			9			—
Forward Physical Contracts	1			—			1			—
NGLs — Forwards/Swaps	8			7			1			—
Power:
Forwards	3			—			3			—
Options — Calls	4			—			4			—
Refined Products — Futures	2			2			—			—
Total commodity derivatives	136			115			21			—
Total Assets	$	187		$	115		$	72		$	—
Liabilities:
Interest rate derivatives	$	(224	)	$	—		$	(224	)	$	—
Preferred Units	(340		)	—			—			(340		)
Embedded derivatives in the Regency Preferred Units	(39		)	—			—			(39		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(12		)	(12		)	—			—
Swing Swaps IFERC	(1		)	—			(1		)	—
Fixed Swaps/Futures	(116		)	(111		)	(5		)	—
Options — Calls	(1		)	—			(1		)	—
NGLs — Forwards/Swaps	(1		)	(1		)	—			—
Power:
Forwards	(1		)	—			(1		)	—
Futures	(1		)	(1		)	—			—
Options — Calls	(1		)	—			(1		)	—
Refined Products — Futures	(1		)	(1		)	—			—
Crude	(4		)	(4		)	—			—
Total commodity derivatives	(139		)	(130		)	(9		)	—
Total Liabilities	$	(742	)	$	(130	)	$	(233	)	$	(379	)

	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 three months ended March 31, 2013. There were no transfers between the fair value hierarchy levels during the three months ended March 31, 2013 or 2012.

Balance, December 31, 2012	$	(356	)
Net unrealized gain included in other income (expense)	(23		)
Balance, March 31, 2013	$	(379	)

XML

Net Income Per Limited Partner Unit

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Net Income Per Limited Partner Unit

NET INCOME PER LIMITED PARTNER UNIT:

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

	Three Months Ended March 31,
	2013		2012
Income from continuing operations	$	300	$	962
Less: Income from continuing operations attributable to noncontrolling interest	224		796
Income from continuing operations, net of noncontrolling interest	76		166
Less: General Partner’s interest in income from continuing operations	—		1
Income from continuing operations available to Limited Partners	$	76	$	165
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	279,959,091		226,730,477
Basic income from continuing operations per Limited Partner unit	$	0.27	$	0.73
Basic income from discontinued operations per Limited Partner unit	$	0.05	$	0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	76	$	165
Dilutive effect of equity-based compensation of subsidiaries	—		(1		)
Diluted income from continuing operations available to Limited Partners	$	76	$	164
Weighted average limited partner units	279,959,091		226,730,477
Diluted income from continuing operations per Limited Partner unit	$	0.27	$	0.73
Diluted income from discontinued operations per Limited Partner unit	$	0.05	$	0.00

The calculation above for the three months ended March 31, 2013 and 2012 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive.

XML

Redeemable Preferred Units

3 Months Ended

Mar. 31, 2013

Temporary Equity Disclosure [Abstract]

Redeemable Preferred Units [Text Block]

REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

On April 1, 2013, ETE completed the redemption (the “Redemption”) of all 3,000,000 of its 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. ETE paid $306 million in cash to GE Regency as consideration for the redeemed units, which represented principal and accrued and unpaid distributions payable thereon. 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. At March 31, 2013 the fair value of the Preferred Units was based on the actual redemption value at April 1, 2013.

XML

Price Risk Management Assets And Liabilities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Deposits with counterparties	$ 23	$ 41
ETP [Member]
Expected gains (losses) related to derivatives to be reclassified into earnings over next year related to amounts currently reported an AOCI	(5)
Deposits with counterparties	23
Price Risk Management Assets [Member]
Option Premiums	1
Price Risk Management Liabilities [Member]
Option Premiums	$ (6)	$ 7

XML

Price Risk Management Assets And Liabilities (Interest Rate Swaps Outstanding) (Details) (Interest Rate Derivatives [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 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	400	[2]	400	[2]
Type	Forward-starting to pay a fixed rate of 4.02% 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	$ 200		$ 0
Type	Pay a floating rate plus a spread of 1.73% 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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Accrued Environmental Liabilities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Environmental Exit Cost [Line Items]
Current	$ 41	$ 46
Non-current	164	166
Total environmental liabilities	$ 205	$ 212

XML

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

3 Months Ended

Mar. 31, 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.

	March 31, 2013		December 31, 2012
Current	$	41	$	46
Non-current	164		166
Total environmental liabilities	$	205	$	212

XML

Debt Obligations (ETP Credit Facility) (Narrative) (Details) (ETP Credit Facility [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013
ETP Credit Facility [Member]
Outstanding borrowings	$ 250
Amount available for future borrowings	2,170
Letters of Credit Outstanding, Amount	76
Weighted average interest rate on amount outstanding	1.70%
Line of Credit Facility, Current Borrowing Capacity	$ 2,500

XML

Price Risk Management Assets And Liabilities

3 Months Ended

Mar. 31, 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 hold 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. Long-term physical contracts are tied to index prices.

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

	March 31, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX (1)	3,057,500	2013-2014	(30,980,000	)	2013-2014
Power (Megawatt):
Forwards	311,150	2013	19,650		2013
Futures	(452,400)	2013	(1,509,300	)	2013
Options — Calls	57,600	2013	1,656,400		2013
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,867,500)	2013-2014	150,000		2013
Swing Swaps IFERC	(11,755,000)	2013	(83,292,500	)	2013
Fixed Swaps/Futures	(6,065,000)	2013-2015	27,077,500		2013
Forward Physical Contracts	2,021,900	2013-2014	11,689,855		2013-2014
NGLs (Bbls):
Forwards/Swaps	(205,000)	2013	(30,000	)	2013
Crude (Bbls) — Futures	(120,000)	2013	—		—
Refined Products (Bbls) — Futures	1,772	2013-2014	(666,000	)	2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(6,960,000)	2013	(18,655,000	)	2013
Fixed Swaps/Futures	(7,260,000)	2013	(44,272,500	)	2013
Hedged Item — Inventory	7,260,000	2013	44,272,500		2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(3,437,500)	2013	—		—
Fixed Swaps/Futures	(9,625,000)	2013	(8,212,500	)	2013
NGLs (Bbls):
Forwards/Swaps	(695,000)	2013	(930,000	)	2013
Crude (Bbls) — Futures	(270,000)	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 losses of $5 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 effected by the inherent volatility of these commodities, which could adversely effect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.

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

	March 31, 2013		December 31, 2012
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	12,257,000	2013	8,395,000	2013-2014
Propane (Gallons):
Forwards/Swaps	1,722,000	2013	3,318,000	2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	188,000	2013-2014	243,000	2013-2014
WTI Crude Oil (Barrels):
Forwards/Swaps	422,000	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)	March 31, 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 4.02% and receive a floating rate	400		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 1.73% and receive a fixed rate of 3.60%	200		—
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 primarily of petrochemical companies and other industrial, small to major oil and gas producers, midstream and power generation companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by 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 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 $23 million and $41 million as of March 31, 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.

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 sheets and recognized in net income or other comprehensive income.

Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2013		December 31, 2012		March 31, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	4	$	8	$	(14	)	$	(10	)
	4		8		(14		)	(10		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	120	$	110	$	(125	)	$	(116	)
Commodity derivatives	62		40		(56		)	(44		)
Current assets held for sale	8		1		—			—
Non-current assets held for sale	—		1		—			—
Current liabilities held for sale	—		—		(2		)	(9		)
Interest rate derivatives	51		55		(224		)	(235		)
Embedded derivatives in Regency Preferred Units	—		—		(39		)	(25		)
	241		207		(446		)	(429		)
Total derivatives	$	245	$	215	$	(460	)	$	(439	)

In addition to the above derivatives, $1 million and $6 million in option premiums were included in price risk management assets and price risk management liabilities, respectively, as of March 31, 2013 are being amortized in 2013. 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	March 31, 2013			December 31, 2012			March 31, 2013			December 31, 2012
Bi-lateral contracts	Price risk management asset (liability)	$	54		$	28		$	(52	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)	183			149			(225		)	(221		)
	Gross fair value	237			177			(277		)	(248		)
Collateral paid to OTC counterparties	Other current assets (liabilities)	—			—			—			2
Counterparty netting	Price risk management asset (liability)	(51		)	(25		)	51			25
Payments on margin deposit	Other current assets (liabilities)	—			—			38			59
	Net fair value	$	186		$	152		$	(188	)	$	(162	)

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

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended March 31,
	2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	2	$	22
Total	$	2	$	22

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended March 31,
		2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	1	$	3
Total		$	1	$	3

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended March 31,
		2013		2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	5	$	(13	)
Total		$	5	$	(13	)

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2013			2012
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	(4	)	$	(11	)
Commodity derivatives — Non-Trading	Cost of products sold	(21		)	—
Commodity derivatives — Non-Trading	Deferred gas purchases	(5		)	—
Interest rate derivatives	Gains on interest rate derivatives	6			27
Embedded derivatives	Other income	(14		)	—
Total		$	(38	)	$	16

XML

Estimates and Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2013

Estimates Disclosure [Abstract]

Estimates

ESTIMATES:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in goodwill impairment tests, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.

XML

Debt Obligations (Senior Notes) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended						3 Months Ended
	Jan. 31, 2013 ETP [Member]	Jan. 31, 2013 Sunoco Logistics [Member]	Mar. 31, 2013 3.6% Senior Notes due February 1, 2023 [Member]	Mar. 31, 2013 5.15% Senior Notes due February 1, 2043 [Member]	Mar. 31, 2013 3.45% Senior Notes due January 2023 [Member]	Mar. 31, 2013 4.95% Senior Notes due January 2043 [Member]	Mar. 31, 2013 Regency Senior Notes [Member]	Mar. 31, 2013 Due November 1, 2023 [Member] Regency Senior Notes [Member]
Debt Instrument [Line Items]
Senior Notes			$ 800	$ 450	$ 350	$ 350
Offering Price for Debt Redemption Percentage							104.688%
Estimated Closing Adjustments								600
Debt Instrument, Interest Rate, Stated Percentage			3.60%	5.15%	3.45%	4.95%	4.50%
Early Repayment of Senior Debt							162
Proceeds from Issuance of Senior Long-term Debt	$ 1,240	$ 691

XML

Investments in Affiliates Investments in Affiliates Narrative (Details) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
AmeriGas [Member]
Schedule of Equity Method Investments [Line Items]
Investment Owned, Balance, Shares	30
Citrus [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership	50.00%
FGT [Member]
Schedule of Equity Method Investments [Line Items]
Percentage Ownership Operating Facility	100.00%
Fayetteville Express Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership	50.00%
RIGS Haynesville Partnership Co. [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership	49.99%
Midcontinent Express Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership	50.00%
PES Joint Venture [Member]
Schedule of Equity Method Investments [Line Items]
Interest ownership	30.00%

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	(179)	(1)	(178)	0	0
Distributions to noncontrolling interest	(333)	0	0	0	(333)
Subsidiary units issued for cash	192	0	10	0	182
Non-cash compensation expense, net of units tendered by employees for tax withholdings	14	0	0	0	14
Capital contributions from noncontrolling interest	11	0	0	0	11
Other, net	(2)	0	0	0	(2)
Other comprehensive income, net of tax	7	0	0	1	6
Net income	322	0	90	0	232
Balance, March 31, 2013 at Mar. 31, 2013	$ 16,382	$ (1)	$ 2,047	$ (11)	$ 14,347

XML

Investments in Affiliates

3 Months Ended

Mar. 31, 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 owns approximately 30 million AmeriGas common units.

• 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 in Panola County, Mississippi.

• HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the RIGS, 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 March 31,
	2013		2012
Revenue	$	4,146	$	1,366
Operating income	349		314
Net income	230		215

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

Equity (Quarterly Distributions Of Available Cash) (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012
Parent Company [Member]
Record Date	May 06, 2013	Feb. 07, 2013
Payment Date	May 17, 2013	Feb. 19, 2013
Distributions paid, rate per unit	$ 0.645	$ 0.635
ETP [Member]
Record Date	May 06, 2013	Feb. 07, 2013
Payment Date	May 15, 2013	Feb. 14, 2013
Distributions paid, rate per unit	$ 0.89375	$ 0.89375
Regency [Member]
Record Date	May 06, 2013	Feb. 07, 2013
Payment Date	May 13, 2013	Feb. 14, 2013
Distributions paid, rate per unit	$ 0.46	$ 0.46
Sunoco Logistics [Member]
Record Date	May 09, 2013	Feb. 08, 2013
Payment Date	May 15, 2013	Feb. 14, 2013
Distributions paid, rate per unit	$ 0.57250	$ 0.54500

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
	Mar. 31, 2013	Mar. 31, 2012
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 2	$ 22
Commodity Derivatives [Member]
Change in Value Recognized in OCI on Derivatives (Effective Portion)	$ 2	$ 22

XML

Investments in Affiliates (Tables)

3 Months Ended

Mar. 31, 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 March 31,
	2013		2012
Revenue	$	4,146	$	1,366
Operating income	349		314
Net income	230		215

XML

Reportable Segments (Assets Segments)(Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Assets	$ 50,140	$ 48,904
ETP Intrastate Transportation and Storage [Member]
Assets	4,579	4,691
ETP Interstate Transportation and Storage [Member]
Assets	11,749	11,794
ETP Midstream [Member]
Assets	4,989	5,098
ETP NGL Transportation and Services [Member]
Assets	3,904	3,765
ETP Retail Marketing [Member]
Assets	4,039	3,926
Investment in Sunoco Logistics [Member]
Assets	10,993	10,291
Investment In Regency [Member]
Assets	6,273	6,157
Corporate And Other [Member]
Assets	4,964	4,372
Adjustments And Eliminations [Member]
Assets	$ (1,350)	$ (1,190)

XML

Supplemental Financial Statement Information (Tables)

3 Months Ended

Mar. 31, 2013

Schedule Of Balance Sheets

BALANCE SHEETS

(unaudited)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	42		$	9
Accounts receivable from related companies	4			11
Other current assets	45			3
Total current assets	91			23
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,016			6,094
INTANGIBLE ASSETS, net	18			19
GOODWILL	9			9
NOTE RECEIVABLE FROM AFFILIATE	166			166
OTHER NON-CURRENT ASSETS, net	53			56
Total assets	$	6,353		$	6,367
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	1		$	1
Accounts payable to related companies	7			15
Interest payable	81			48
Price risk management liabilities	5			5
Accrued and other current liabilities	1			1
Current maturities of long-term debt	4			4
Total current liabilities	99			74
LONG-TERM DEBT, less current maturities	3,871			3,840
PREFERRED UNITS	340			331
OTHER NON-CURRENT LIABILITIES	8			9
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	—
Limited Partners	2,047			2,125
Accumulated other comprehensive loss	(11		)	(12		)
Total partners’ capital	2,035			2,113
Total liabilities and partners’ capital	$	6,353		$	6,367

Schedule Of Statements Of Operations

STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended March 31,
	2013			2012
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(6	)	$	(31	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(64		)	(43		)
Bridge loan related fees	—			(62		)
Equity in earnings of affiliates	168			307
Other, net	(8		)	(5		)
INCOME BEFORE INCOME TAXES	90			166
Income tax expense	—			—
NET INCOME	90			166
GENERAL PARTNER’S INTEREST IN NET INCOME	—			1
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	90		$	165

Parent Company [Member]

Schedule Of Statements Of Cash Flows

STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2013			2012
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	182		$	146
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions	—			(1,558		)
Note receivable from affiliate	—			(221		)
Net cash used in investing activities	—			(1,779		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	95			1,960
Principal payments on debt	(65		)	(72		)
Distributions to partners	(179		)	(140		)
Debt issuance costs	—			(76		)
Net cash provided by (used in) financing activities	(149		)	1,672
DECREASE IN CASH AND CASH EQUIVALENTS	33			39
CASH AND CASH EQUIVALENTS, beginning of period	9			18
CASH AND CASH EQUIVALENTS, end of period	$	42		$	57

XML

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

3 Months Ended

Mar. 31, 2013

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

Regulatory Matters, Commitments, Contingencies And Environmental Liabilities

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Regulatory Matters

Southern Union and its Subsidiaries

The FERC is currently conducting an audit of PEPL, 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. The audit is related to the period from January 1, 2010 through December 31, 2011 and is pending the issuance of a draft audit report.

Contingent Residual Support Agreement — AmeriGas

In January 2012, AmeriGas Finance LLC, a wholly owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% senior notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the Senior Notes issuance from AmeriGas Finance LLC through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes.

In connection with ETP’s contribution of its Propane Business, ETP entered into a CRSA with AmeriGas, AmeriGas Finance LLC, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will provide contingent, residual support of the Supported Debt, as defined in the CRSA.

PEPL Holdings Guarantee of Collection

In accordance with the Contribution Agreement pursuant to which Southern Union contributed SUGS to Regency, 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, under the Contribution Agreement 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 the guarantee of collection 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.

NGL Pipeline Regulation

We have interests in NGL pipelines located in Texas. We believe that these pipelines do not provide interstate service and that they are thus not subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of our NGL facilities will remain unchanged; however, should they be found jurisdictional, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

Commitments

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled $33 million and $7 million for the three months endedMarch 31, 2013 and 2012, respectively, which include contingent rentals totaling $4 million for the three months ended March 31, 2013. During the three months ended March 31, 2013, $5 million 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 capital 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 is pending approval by the state court. A final approval hearing is set for June 26, 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 December 31, 2012, 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 its 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 deadline for the remaining defendants to file an answer or otherwise respond was late April 2013. Trial in this action is not currently set.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of March 31, 2013 and December 31, 2012, accruals of approximately $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 March 31, 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).  In the event that Plaintiffs refuse Panhandle’s pending request for voluntary dismissal, Panhandle will continue to vigorously defend the case.  Southern Union believes it has no liability associated with this proceeding.

Simmons v. Southern Union Company. Cause No. 1316-CV-07265, in the Circuit Court of Jackson County, Missouri, Kansas City:On March 22, 2013, the first lawsuit related to the February 19, 2013 natural gas incident at JJ's Restaurant was filed in Missouri state court on behalf of six injured restaurant employees. The defendants include Southern Union Company d/b/a MGE, USIC Locating Services, Inc. (the utility marking service), Heartland Midwest, LLC (the directional boring company and contractor of Time Warner Cable Media, Inc.), Time Warner Cable Media, Inc., Missouri One Call System, Inc., (Missouri's notification center for utility locates), and Mike Palier (MGE's first responder).  Plaintiffs' claims include negligence and strict liability for inherently dangerous activities. Plaintiffs have not specified an amount of damages, but seek punitive damages against MGE and certain other defendants in a jury trial. No trial date has been set.

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.  The hearing officer has stayed discovery until resolution of a separate matter concerning the applicability of attorney-client privilege to legal billing invoices.  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 March 31, 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.

	March 31, 2013		December 31, 2012
Current	$	41	$	46
Non-current	164		166
Total environmental liabilities	$	205	$	212

During the three months ended March 31, 2013, Sunoco recorded $7 million 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.