Energy Transfer LP - Quarter Report: 2012 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 2012



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

Commission file number 1-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)



Delaware		30-0108820
(state or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	ý	Accelerated filer	¨

Non-accelerated filer	£ (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

At May 2, 2012, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P. 279,955,608 Common Units

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FORM 10-Q

TABLE OF CONTENTS

Energy Transfer Equity, L.P. and Subsidiaries



PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	1

Consolidated Statements of Operations – Three Months Ended March 31, 2012 and 2011	3

Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2012 and 2011	4

Consolidated Statement of Equity – Three Months Ended March 31, 2012	5

Consolidated Statements of Cash Flows – Three Months Ended March 31, 2012 and 2011	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	43

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	58

ITEM 4. CONTROLS AND PROCEDURES	62

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	62

ITEM 1A. RISK FACTORS	62

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	65

ITEM 3. DEFAULTS UPON SENIOR SECURITIES	65

ITEM 4. MINE SAFETY DISCLOSURES	65

ITEM 5. OTHER INFORMATION	65

ITEM 6. EXHIBITS	66

SIGNATURE	67

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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 II — Other Information – Item 1A. Risk Factors” included in this Quarterly Report on Form 10-Q, as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission on February 22, 2012.

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

AROs		asset retirement obligations

Bbls		barrels

Bcf		billion cubic feet

Btu		British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content

CAA		Federal Clean Air Act

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

CFTC		Commodities Futures Trading Commission

Credit Suisse		Credit Suisse Securities (USA) LLC

CRSA		Contingent Residual Support Agreement

DER		Distribution equivalent rights

DRIP		Distribution Reinvestment Plan

DOT		U.S. Department of Transportation

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

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EPA		U.S. Environmental Protection Agency

Exchange Act		Securities Exchange Act of 1934

FDOT/FTE		Florida Department of Transportation, Florida's Turnpike Enterprise

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.

HOLP		Heritage Operating, L.P.

ICA		Interstate Commerce Act

IDRs		incentive distribution rights

LDH		LDH Energy Asset Holdings LLC

LIBOR		London Interbank Offered Rate

LNG		Liquefied natural gas

LNG Holdings		Trunkline LNG Holdings, LLC

Lone Star		Lone Star NGL LLC

MDPU		Massachusetts Department of Public Utilities

MEP		Midcontinent Express Pipeline LLC

MGP		manufactured gas plant

MMBtu		million British thermal units

NGA		Natural Gas Act

NGL		natural gas liquid, such as propane, butane and natural gasoline

NMED		New Mexico Environmental Department

NOL		net operating loss

NYMEX		New York Mercantile Exchange

OTC		over-the-counter

Other Post-retirement Plans		postretirement health care and life insurance plans

OSHA		Federal Occupational Safety and Health Act

Panhandle		Panhandle Eastern Pipe Line Company, LP and its subsidiaries

PCB		polychlorinated biphenyl

Pension Plans		funded non-contributory defined benefit pension plans

PEPL		Panhandle Eastern Pipe Line Company, LP

PHMSA		Pipeline Hazardous Materials Safety Administration

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.

iii

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Propane Contribution		ETP's contribution of its Propane Business to AmeriGas

Ranch JV		Ranch Westex JV LLC

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

Reservoir		a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers

Sea Robin Pipeline		Sea Robin Pipeline Company LLC

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 Company on March 26, 2012

SUGS		Southern Union Gas Services

Sunoco		Sunoco Inc.

Sunoco Logistics		Sunoco Logistics Partners L.P.

TCEQ		Texas Commission on Environmental Quality

Tcf		trillion cubic feet

Transwestern		Transwestern Pipeline Company, LLC

Trunkline LNG		Trunkline LNG Company, LLC

WTI		West Texas Intermediate Crude

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)



	March 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	293,057		$	126,342
Marketable securities	11			1,229
Accounts receivable, net of allowance for doubtful accounts of $3,213 and $8,841 as of March 31, 2012 and December 31, 2011, respectively	851,628			680,491
Accounts receivable from related companies	26,424			100,406
Inventories	379,021			327,963
Exchanges receivable	61,319			21,307
Price risk management assets	38,140			15,802
Other current assets	224,170			181,904
Total current assets	1,873,770			1,455,444
PROPERTY, PLANT AND EQUIPMENT	23,068,083			16,529,339
ACCUMULATED DEPRECIATION	(1,664,262		)	(1,970,777		)
	21,403,821			14,558,562
ADVANCES TO AND INVESTMENTS IN AFFILIATES	4,667,594			1,496,600
LONG-TERM PRICE RISK MANAGEMENT ASSETS	25,345			26,011
GOODWILL	3,400,542			2,038,975
INTANGIBLE ASSETS, net	960,725			1,072,291
OTHER NON-CURRENT ASSETS, net	490,304			248,910
Total assets	$	32,822,101		$	20,896,793

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)



	March 31, 2012		December 31, 2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	518,047	$	512,023
Accounts payable to related companies	2,658		33,208
Exchanges payable	124,993		17,957
Price risk management liabilities	72,068		90,053
Accrued and other current liabilities	948,659		763,912
Current maturities of long-term debt	109,127		424,160
Total current liabilities	1,775,552		1,841,313

LONG-TERM DEBT, less current maturities	17,391,195		10,946,864
PREFERRED UNITS (Note 11)	326,950		322,910
ACCUMULATED DEFERRED INCOME TAXES	2,010,667		217,244
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES	180,924		81,415
OTHER NON-CURRENT LIABILITIES	300,178		26,958

COMMITMENTS AND CONTINGENCIES (Note 16)

PREFERRED UNITS OF SUBSIDIARY (Note 11)	72,196		71,144

EQUITY:
General Partner	357		321
Limited Partners:
Common Unitholders	2,418,541		52,485
Accumulated other comprehensive income	6,570		678
Total partners’ capital	2,425,468		53,484
Noncontrolling interest	8,338,971		7,335,461
Total equity	10,764,439		7,388,945
Total liabilities and equity	$	32,822,101	$	20,896,793

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)



	Three Months Ended March 31,
	2012			2011
REVENUES:
Natural gas sales	$	504,610		$	709,324
NGL sales	532,299			275,152
Gathering, transportation and other fees	500,962			412,256
Retail propane sales	75,445			528,466
Other	75,815			63,922
Total revenues	1,689,131			1,989,120
COSTS AND EXPENSES:
Cost of products sold	1,022,200			1,201,426
Operating expenses	174,905			220,696
Depreciation and amortization	161,201			139,256
Selling, general and administrative	148,262			63,499
Total costs and expenses	1,506,568			1,624,877
OPERATING INCOME	182,563			364,243
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(213,330		)	(167,929		)
Bridge loan related fees	(62,241		)	—
Equity in earnings of affiliates	75,232			25,441
Gain on deconsolidation of Propane Business	1,055,944			—
Losses on disposal of assets	(1,060		)	(1,754		)
Loss on extinguishment of debt	(115,023		)	—
Gains on non-hedged interest rate derivatives	27,490			1,520
Other, net	13,306			(12,526		)
INCOME BEFORE INCOME TAX EXPENSE	962,881			208,995
Income tax expense	1,579			9,903
NET INCOME	961,302			199,092
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	794,880			110,452
NET INCOME ATTRIBUTABLE TO PARTNERS	166,422			88,640
GENERAL PARTNER’S INTEREST IN NET INCOME	506			274
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	165,916		$	88,366
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.73		$	0.40
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING	226,730,477			222,954,674
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.73		$	0.40
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING	226,730,477			222,954,674

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(unaudited)



	Three Months Ended March 31,
	2012			2011
Net income	$	961,302		$	199,092
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	65			(13,539		)
Change in value of derivative instruments accounted for as cash flow hedges	21,649			(10,838		)
Change in value of available-for-sale securities	(114		)	608
	21,600			(23,769		)
Comprehensive income	982,902			175,323
Less: Comprehensive income attributable to noncontrolling interest	810,588			92,263
Comprehensive income attributable to partners	$	172,314		$	83,060

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2012

(Dollars in thousands)

(unaudited)



	General Partner			Common Unitholders			Accumulated Other Comprehensive Income		Noncontrolling Interest			Total
Balance, December 31, 2011	$	321		$	52,485		$	678	$	7,335,461		$	7,388,945
Distributions to partners	(433		)	(139,358		)	—		—			(139,791		)
Distributions to noncontrolling interest	—			—			—		(219,990		)	(219,990		)
Units issued in Southern Union Merger (See Note 3)	—			2,354,490			—		—			2,354,490
Subsidiary units issued for cash	(36		)	(14,634		)	—		399,313			384,643
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			164			—		11,967			12,131
Capital contributions from noncontrolling interest	—			—			—		5,133			5,133
Other, net	(1		)	(522		)	—		(3,501		)	(4,024		)
Other comprehensive income, net of tax	—			—			5,892		15,708			21,600
Net income	506			165,916			—		794,880			961,302
Balance, March 31, 2012	$	357		$	2,418,541		$	6,570	$	8,338,971		$	10,764,439

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)



	Three Months Ended March 31,
	2012			2011
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:
Net income	$	961,302		$	199,092
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	161,201			139,256
Deferred income taxes	(2,138		)	1,101
Gain on curtailment of other postretirement benefit plans	(15,332		)	—
Amortization of finance costs charged to interest	5,449			5,080
Bridge loan related fees	62,241			—
Non-cash compensation expense	12,155			11,385
Gain on deconsolidation of Propane Business	(1,055,944		)	—
Losses on disposal of assets	1,060			1,754
Loss on extinguishment of debt	115,023			—
Distributions in excess of (less than) equity in earnings of affiliates, net	(18,076		)	21,582
Other non-cash	2,545			16,569
Changes in operating assets and liabilities, net of effects of acquisitions and deconsolidation	(150,130		)	(37,670		)
Net cash provided by operating activities	79,356			358,149
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Southern Union Merger, net of cash received	(2,971,764		)	—
Cash paid for acquisitions, net of cash received	(10,066		)	(3,060		)
Capital expenditures (excluding allowance for equity funds used during construction)	(594,537		)	(279,587		)
Contributions in aid of construction costs	5,732			2,754
Distributions from (advances to) affiliates, net	3,967			(11,053		)
Proceeds from the sale of assets	25,715			687
Proceeds from the contribution of Propane Business	1,383,802			—
Net cash used in investing activities	(2,157,151		)	(290,259		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	4,786,963			997,094
Repayments of long-term debt	(2,473,560		)	(763,615		)
Subsidiary equity offering, net of issue costs	384,643			57,373
Distributions to partners	(139,791		)	(120,763		)
Debt issuance costs	(96,920		)	—
Distributions to noncontrolling interest	(219,990		)	(179,631		)
Capital contributions from noncontrolling interest	5,133			—
Other, net	(1,968		)	(1,580		)
Net cash provided by (used in) financing activities	2,244,510			(11,122		)
INCREASE IN CASH AND CASH EQUIVALENTS	166,715			56,768
CASH AND CASH EQUIVALENTS, beginning of period	126,342			86,264
CASH AND CASH EQUIVALENTS, end of period	$	293,057		$	143,032

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(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, and Southern Union. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

At March 31, 2012, our equity interests in ETP and Regency consisted of:



	General Partner Interest (as a % of total partnership interest)		IDRs		Common Units	Total Ownership (as a % and net of any treasury units)
ETP	1.5	%	100	%	52,476,059	24	%
Regency	1.6	%	100	%	26,266,791	17	%

On March 26, 2012, we acquired all of the outstanding shares of Southern Union for approximately $3.01 billion in cash and approximately 57.0 million ETE Common Units. See Note 3 for more information regarding the Southern Union Merger.

The unaudited consolidated financial statements of ETE presented herein for the three month periods ended March 31, 2012 and 2011 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”);


•	our wholly-owned subsidiary, Southern Union (see description of its operations below under “Business Operations”); and


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

Our unaudited consolidated financial statements include the results of operations of Southern Union from March 26, 2012, the date we acquired Southern Union, through March 31, 2012.

Business Operations

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. Effective with the acquisition of Southern Union, the Parent Company also generates cash flows through its wholly-owned subsidiary, Southern Union. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. 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 21 for stand-alone financial information apart from that of the consolidated partnership information included herein.

The following is a brief description of our operating entities:

•

ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% interest in Lone Star , a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. Concurrent with the Parent Company's acquisition of Southern Union, ETP acquired a 50% interest in Citrus, which owns FGT (see Note 3).

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•

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 California, Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

•

Southern Union is engaged primarily in the transportation, storage, gathering, processing and distribution of natural gas. Southern Union owns and operates interstate pipeline that transports natural gas from the Gulf of Mexico, South Texas and the Panhandle regions of Texas and Oklahoma to major U.S. markets in the Midwest and Great Lakes regions. It owns and operates a LNG import terminal located on Louisiana's Gulf Coast. Through SUGS, it owns natural gas and NGL pipelines, cryogenic plants, treating plants and is engaged in connecting producing wells of exploration and production companies to its gathering system, treating natural gas to remove impurities to meet pipeline quality specifications, processing natural gas for the removal of NGLs and redelivering natural gas and NGLs to a variety of markets in West Texas and New Mexico. Southern Union also has regulated utility operations in Missouri and Massachusetts.

See Note 20 for discussion regarding our reportable segments.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2011, 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, 2012 and for the three months period ended March 31, 2012 and 2011, 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 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, 2012, and the Partnership’s results of operations and cash flows for the three months ended March 31, 2012 and 2011. 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, 2011, as filed with the SEC on February 22, 2012.

Certain prior period amounts have been reclassified to conform to the 2012 presentation. These reclassifications had no impact on net income or total equity.


2.	ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES:

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 the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

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Significant Accounting Policies

As a result of the Southern Union Merger on March 26, 2012, the following significant accounting policies have been added to our significant accounting policies described in our Form 10-K for the year ended December 31, 2011.

Pensions and Other Postretirement Benefit Plans

Employers are required to recognize in their balance sheets the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the change in the funded status of the plan in the year in which the change occurs through Accumulated other comprehensive income in equity. See Note 14 for further information regarding pensions and other postretirement benefit plans.

Revenue Recognition for Southern Union's Natural Gas Distribution Operations

In Southern Union's natural gas distribution operations, natural gas utility customers are billed on a monthly-cycle basis. The related cost of natural gas and revenue taxes are matched with cycle-billed revenues through utilization of purchased natural gas adjustment provisions in tariffs approved by the regulatory agencies having jurisdiction. Revenues from natural gas delivered but not yet billed are accrued, along with the related natural gas purchase costs and revenue-related taxes.


3.	ACQUISITIONS:

Southern Union Merger

On March 26, 2012, Sigma Acquisition Corporation, a Delaware corporation and a wholly-owned subsidiary of ETE, completed its acquisition of Southern Union. Southern Union is the surviving entity in the merger and will continue to operate as our wholly-owned subsidiary of ETE. The assets acquired as a result of this merger significantly expand our existing geographic footprint of natural gas pipeline and natural gas transportation capacity and into natural gas utilities distribution, and are complementary to the assets owned and operated by our other entities.

Under the terms of the merger agreement, Southern Union stockholders were able to elect to exchange each outstanding share of Southern Union common stock for $44.25 in cash or 1.00 ETE Common Unit, with no more than 60% of the aggregate merger consideration payable in cash and no more than 50% of the merger consideration payable in ETE Common Units. Based on the final results of the merger consideration, elections were as follows:


•	approximately 54% of outstanding Southern Union shares, or 67,985,929 shares, received cash for total cash consideration of $3.01 billion; and


•	approximately 46% of outstanding Southern Union shares, or 56,981,860 shares, received ETE Common Units valued at $2.35 billion at the time of the merger.

Effective with the closing of the transaction, Southern Union's common stock is no longer publicly traded.

Citrus Merger

In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owns an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units. See Note 4 for more information regarding ETP's equity method investment in Citrus.

In connection with the Citrus Merger, we relinquished our rights to approximately $220 million of IDRs from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the transaction.

Pursuant to the merger agreement, we also granted ETP a right of first offer with respect to any disposition by us or SUGS, a subsidiary of Southern Union that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.

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Summary of Assets Acquired and Liabilities Assumed

We accounted for the Southern Union Merger using the acquisition method of accounting. The acquisition method of accounting requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet presented as of March 31, 2012 reflects the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming results to determine the final purchase price allocation. The purchase price allocation is expected to be finalized in the third quarter of 2012.

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



Total current assets	$	560,041
Property, plant and equipment	7,121,935
Goodwill	1,955,691
Intangible assets	47,000
Regulatory assets	136,280
Investments in unconsolidated affiliates	2,022,784
Other assets	26,822
	11,870,553

Total current liabilities	886,908
Long-term debt obligations	3,565,260
Deferred income taxes	1,771,407
Other non-current liabilities	284,110
	6,507,685
Total consideration	5,362,868
Cash received	36,613
Total consideration, net of cash received	$	5,326,255

Other non-current liabilities assumed includes approximately $46.0 million of AROs, which are primarily related to owned natural gas storage wells and offshore lines and platforms. At the end of the useful life of these underlying assets, Southern Union is legally or contractually required to abandon in place or remove the asset. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. Although a number of other onshore assets in Southern Union's system are subject to agreements that give rise to an ARO upon the discontinued use of the assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement.

Other current liabilities assumed includes approximately $65.3 million for accrued compensation of certain terminated Southern Union employees that had employment agreements with South Union and severance costs associated with administrative headcount reductions.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three months ended March 31, 2012 and 2011 are presented as if the Southern Union Merger had been completed on January 1, 2011.



	Three Months Ended March 31,
	2012		2011
Revenues	$	2,322,780	$	2,735,942
Net income	969,641		218,699
Net income attributable to partners	173,070		99,571
Basic net income per Limited Partner unit	$	0.61	$	0.35
Diluted net income per Limited Partner unit	$	0.61	$	0.35

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The pro forma consolidated results of operations include adjustments to:

•include the results of Southern Union for all periods presented;


•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;

•include incremental interest expense related to financing the transactions;

•adjust for one-time expenses; and

•adjust for relative changes in ownership resulting from the transactions.

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

Southern Union's revenue and net loss since the acquisition date to March 31, 2012 included in our consolidated statement of operations were $39.7 million and $38.5 million, respectively.

Expenses Related to the Southern Union Merger

As a result of the acquisition, we recognized $29.9 million of general and administrative costs during the three months ended March 31, 2012.

Pending Sunoco Merger

On April 30, 2012, ETP announced that it had entered into a definitive merger agreement whereby ETP will acquire Sunoco in a common unit and cash transaction valued at $5.3 billion based on ETP's closing price on April 27, 2012. Under the terms of the merger agreement, Sunoco shareholders would receive, for each Sunoco common share, either $50.00 in cash, 1.0490 ETP Common Units or a combination of $25.00 in cash and 0.5245 ETP Common Units. The aggregate cash paid and ETP Common Units issued will be capped so that the cash and ETP Common Units will each represent 50% of the aggregate consideration. Upon closing, Sunoco shareholders are expected to own approximately 20% of ETP's outstanding limited partner interests. This transaction is expected to close in the third or fourth quarter of 2012, subject to approval by Sunoco's shareholders and customary regulatory approvals.

In connection with the transaction, we have agreed to relinquish our right to approximately $210 million of IDRs from ETP that we would otherwise receive over 12 consecutive quarters following the closing of the transaction.

Sunoco owns the general partner interest of Sunoco Logistics, consisting of a 2% ownership interest and IDRs, and 32.4% of the outstanding common units of Sunoco Logistics. Sunoco also generates cash flow from a portfolio of 4,900 retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States.

Sunoco Logistics is a publicly traded limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary pipeline, terminalling and crude oil acquisition and marketing assets. The refined products pipelines business consists of approximately 2,500 miles of refined products pipelines located in the northeast, midwest and southwest United States, and equity interests in four refined products pipelines. The crude oil pipeline business consists of approximately 5,400 miles of crude oil pipelines, located principally in Oklahoma and Texas. The terminal facilities business consists of approximately 42 million shell barrels of refined products and crude oil terminal capacity (including approximately 22 million shell barrels of capacity at the Nederland Terminal on the Gulf Coast of Texas and approximately 5 million shell barrels of capacity at the Eagle Point terminal on the banks of the Delaware River in New Jersey). The crude oil acquisition and marketing business involves the acquisition and marketing of crude oil and is principally conducted in Oklahoma and Texas and consists of approximately 190 crude oil transport trucks and approximately 120 crude oil truck unloading facilities.

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4.	INVESTMENTS IN AFFILIATES:

Citrus Corp.

ETP acquired a 50% interest in Citrus, which owns 100% of FGT on March 26, 2012. El Paso Corporation owns the remaining 50% interest in Citrus. In exchange for the interest in Citrus, Southern Union received $1.9 billion in cash and $105 million of ETP Common Units. ETP initially recorded its investment in Citrus at $2.0 billion, which exceeded its proportionate share of Citrus' equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting.

AmeriGas Partners, L.P.

On January 12, 2012, ETP contributed its Propane Business to AmeriGas in exchange for approximately $1.46 billion in cash and approximately 29.6 million AmeriGas Common Units valued at $1.12 billion at the time of the contribution. In addition, AmeriGas assumed approximately $71 million of existing debt of the Propane Business. ETP recognized a gain on deconsolidation of $1.06 billion and recorded $39.4 million of equity in earnings related to AmeriGas for the three months ended March 31, 2012.

ETP's investment in AmeriGas initially reflected $639.6 million in excess of the proportionate share of AmeriGas' limited partners' capital. Of this excess fair value, $177.3 million is being amortized over a weighted average period of 12 years and $462.3 million is being treated as equity method goodwill and non-amortizable intangible assets.

We have not reflected the Propane operations as discontinued operations as ETP will have a continuing involvement in this business as a result of the investment in AmeriGas.

Midcontinent Express Pipeline LLC

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.

RIGS Haynesville Partnership Co.

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.

Fayetteville Express Pipeline LLC

ETP owns a 50% interest in the FEP, which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi.

Summarized Financial Information

The following tables present aggregated selected income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis for all periods presented).



	Three Months Ended March 31,
	2012		2011
Revenue	$	1,365,877	$	1,155,218
Operating income	314,081		277,028
Net income	215,258		219,141

In addition to the equity method investments described above, ETP and Southern Union each have other equity method investments.

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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.

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

Non-cash investing and financing activities are as follows:



	Three Months Ended March 31,
	2012			2011
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	244,883		$	107,451
Gain (loss) from subsidiary common unit transactions	$	(14,670	)	$	7,172
AmeriGas limited partner interest received in Propane Contribution (see Note 4)	$	1,123,003		$	—
NON-CASH FINANCING ACTIVITIES:
Issuance of common units in connection with Southern Union Merger (see Note 3)	$	2,354,490		$	—
Subsidiary issuance of common units in connection with acquisition	$	105,000		$	—


6.	INVENTORIES:

Inventories consisted of the following:



	March 31, 2012		December 31, 2011
Natural gas and NGLs, excluding propane	$	253,906	$	146,132
Propane	2,895		86,958
Appliances, parts and fittings and other	122,220		94,873
Total inventories	$	379,021	$	327,963

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.


7.	GOODWILL AND INTANGIBLE ASSETS:

A net increase in goodwill of $1.36 billion was recorded during the three months ended March 31, 2012, which includes goodwill of $1.96 billion recorded as a result of the Southern Union Merger, partially offset by a decrease of $605.6 million as a result of ETP's contribution of its Propane Business to AmeriGas.

The goodwill recorded as a result of the Southern Union Merger is primarily due to expected commercial and operational synergies and is subject to change based on final purchase price allocations. None of the goodwill recorded as a result of this transaction is deductible for tax purposes. See Note 3 for further discussion of Southern Union Merger.

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8.	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. 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. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.

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 and carrying amount of our consolidated debt obligations as of March 31, 2012 was $18.83 billion and $17.50 billion, respectively. As of December 31, 2011, the aggregate fair value and carrying amount of our consolidated debt obligations was $12.21 billion and $11.37 billion, respectively. We consider the fair value of our consolidated debt obligations as Level 2 since the value is based on similar liabilities.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2012 and December 31, 2011 based on inputs used to derive their fair values:



	Fair Value Measurements at March 31, 2012
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	11		$	11		$	—		$	—
Interest rate derivatives	36,550			—			36,550			—
Commodity derivatives:
Condensate — Forward Swaps	44			—			44			—
Natural Gas:
Basis Swaps IFERC/NYMEX	47,657			47,657			—			—
Swing Swaps IFERC	19,093			2,856			16,237			—
Fixed Swaps/Futures	181,877			170,565			11,312			—
Options — Puts	6,765			—			6,765			—
Forward Physical Swaps	3,367			—			3,367			—
NGLs:
Forward Swaps	394			—			394			—
Options — Puts	880			—			880			—
Power:
Forwards	11,562			364			11,198			—
Options — Calls	107			107			—			—
Options — Puts	85			85			—			—
Total commodity derivatives	271,831			221,634			50,197			—
Total Assets	$	308,392		$	221,645		$	86,747		$	—
Liabilities:
Interest rate derivatives	$	(157,544	)	$	—		$	(157,544	)	$	—
Preferred Units	(326,950		)	—			—			(326,950		)
Embedded derivatives in the Regency Preferred Units	(38,553		)	—			—			(38,553		)
Commodity derivatives:
Condensate — Forward Swaps	(2,178		)	—			(2,178		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(73,305		)	(73,305		)	—			—
Swing Swaps IFERC	(20,646		)	(5,024		)	(15,622		)	—
Fixed Swaps/Futures	(155,028		)	(116,877		)	(38,151		)	—
Options — Calls	(2		)	—			(2		)	—
Forward Physical Swaps	(918		)	—			(918		)	—
NGLs — Forward Swaps	(3,809		)	—			(3,809		)	—
Power:
Forwards	(11,152		)	(383		)	(10,769		)	—
Options — Calls	(40		)	(40		)	—			—
Propane — Forward Swaps	(879		)	—			(879		)	—
Total commodity derivatives	(267,957		)	(195,629		)	(72,328		)	—
Total Liabilities	$	(791,004	)	$	(195,629	)	$	(229,872	)	$	(365,503	)

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	Fair Value Measurements at December 31, 2011
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	1,229		$	1,229		$	—		$	—
Interest rate derivatives	36,301			—			36,301			—
Commodity derivatives:
Condensate — Forward Swaps	538			—			538			—
Natural Gas:
Basis Swaps IFERC/NYMEX	62,924			62,924			—			—
Swing Swaps IFERC	15,002			1,687			13,315			—
Fixed Swaps/Futures	218,479			214,572			3,907			—
Options — Puts	6,435			—			6,435			—
Forward Physical Swaps	699			—			699			—
NGLs:
Forward Swaps	94			—			94			—
Options — Puts	309			—			309			—
Propane — Forward Swaps	9			—			9			—
Total commodity derivatives	304,489			279,183			25,306			—
Total Assets	$	342,019		$	280,412		$	61,607		$	—
Liabilities:
Interest rate derivatives	$	(117,490	)	$	—		$	(117,490	)	$	—
Preferred Units	(322,910		)	—			—			(322,910		)
Embedded derivatives in the Regency Preferred Units	(39,049		)	—			—			(39,049		)
Commodity derivatives:
Condensate — Forward Swaps	(1,567		)	—			(1,567		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(82,290		)	(82,290		)	—			—
Swing Swaps IFERC	(16,074		)	(3,061		)	(13,013		)	—
Fixed Swaps/Futures	(148,111		)	(148,111		)	—			—
Options — Calls	(12		)	—			(12		)	—
Forward Physical Swaps	(712		)	—			(712		)	—
NGLs — Forward Swaps	(8,561		)	—			(8,561		)	—
Propane — Forward Swaps	(4,131		)	—			(4,131		)	—
Total commodity derivatives	(261,458		)	(233,462		)	(27,996		)	—
Total Liabilities	$	(740,907	)	$	(233,462	)	$	(145,486	)	$	(361,959	)

The following table presents the material unobservable inputs used to estimate the fair value of the Preferred Units and the embedded derivatives in Regency's Preferred Units:



	Unobservable Input	March 31, 2012
Preferred Units	Yield	6.44	%
Embedded derivatives in the Regency Preferred Units	Credit Spread	6.89	%
	Volatility	16.06	%

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Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency's cost of equity and U. S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency's historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.

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, 2012. There were no transfers between the fair value hierarchy levels during the three months ended March 31, 2012 or 2011.



Balance, December 31, 2011	$	(361,959	)
Net unrealized losses included in other income (expense)	(3,544		)
Balance, March 31, 2012	$	(365,503	)


9.	NET INCOME PER LIMITED PARTNER UNIT:

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



	Three Months Ended March 31,
	2012			2011
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	165,916		$	88,366
Weighted average Limited Partner units	226,730,477			222,954,674
Basic net income per Limited Partner unit	$	0.73		$	0.40
Diluted Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	165,916		$	88,366
Dilutive effect of equity-based compensation of subsidiaries	(846		)	(204		)
Diluted net income available to Limited Partners	$	165,070		$	88,162
Weighted average Limited Partner units	226,730,477			222,954,674
Diluted net income per Limited Partner unit	$	0.73		$	0.40

The calculation above for the three months ended March 31, 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. The Preferred Units have a liquidation preference of $300 million and are subject to mandatory conversion as discussed in Note 11.

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10.	DEBT OBLIGATIONS:

Our debt obligations consisted of the following:



	March 31, 2012			December 31, 2011
Parent Company Indebtedness:
ETE Senior Notes, due October 15, 2020	$	1,800,000		$	1,800,000
ETE Senior Secured Term Loan, due March 26, 2017	2,000,000			—
ETE Senior Secured Revolving Credit Facility	—			71,500
Subsidiary Indebtedness:
ETP Senior Notes (aggregated)	7,800,000			6,550,000
Transwestern Senior Unsecured Notes (aggregated)	870,000			870,000
HOLP Senior Secured Notes (aggregated)	—			71,314
Regency Senior Notes (aggregated)	1,350,000			1,350,000
Southern Union Senior Notes:
7.6% Senior Notes due February 1, 2024	359,765			—
8.25% Senior Notes due November 14, 2029	300,000			—
7.24% to 9.44% First Mortgage Bonds due February 15, 2020 to December 15, 2027	19,500			—
7.2% Junior Subordinated Notes due November 1, 2066	600,000			—
Notes Payable	7,603			—
Panhandle:
6.05% Senior Notes due August 15, 2013	250,000			—
6.2% Senior Notes due November 1, 2017	300,000			—
7.0% Senior Notes due June 15, 2018	400,000			—
8.125% Senior Notes due June 1, 2019	150,000			—
7.0% Senior Notes due July 15, 2029	66,305			—
Term Loan due February 23, 2015	455,000			—
Revolving Credit Facilities:
ETP Revolving Credit Facility	190,000			314,438
Regency Revolving Credit Facility	250,000			332,000
Southern Union Revolving Credit Facility	165,000			—
Other Long-Term Debt	704			10,434
Unamortized premiums (discounts), net	156,201			(10,309		)
Fair value adjustments related to interest rate swaps	10,244			11,647
	17,500,322			11,371,024
Current maturities	(109,127		)	(424,160		)
	$	17,391,195		$	10,946,864

The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $166.4 million in net unamortized premiums and fair value adjustments related to interest rate swaps:



2012 (remainder)	$	108,844
2013	600,944
2014	630,873
2015	1,205,863
2016	730,847
Thereafter	14,056,507
Total	$	17,333,878

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ETE Senior Secured Term Loan

We used the net proceeds from our Senior Secured Term Loan, along with proceeds received from ETP in the Citrus Merger, to fund the cash portion of the Southern Union Merger and pay related fees and expenses, including existing borrowings under our revolving credit facility and for general partnership purposes.

Borrowings bear interest at either the Eurodollar rate plus an applicable margin or the alternative base rate plus an applicable margin. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are 3.0% for Eurodollar loans and from 2.0% for base rate loans. The effective interest rate on the amount outstanding as of March 31, 2012 was 3.75%.

Southern Union Junior Subordinated Notes

Southern Union has interest rate swap agreements that effectively fix the interest rate applicable to the floating rate on $525 million of the $600 million Junior Subordinated Notes due 2066. The interest rate on the remaining notes is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the Junior Subordinated Notes was $75 million at an effective interest rate of 3.45% at March 31, 2012.

Panhandle Term Loans

In February 2012, Southern Union refinanced LNG Holdings' $455 million term loan due March 2012 with an unsecured three-year term loan facility due February 2015, with LNG Holdings as borrower and PEPL and Trunkline LNG as guarantors and a floating interest rate tied to LIBOR plus a margin based on the rating of PEPL's senior unsecured debt. The effective interest rate of PEPL's term loan was 1.87% at March 31, 2012.

Bridge Term Loan Facility

Upon obtaining permanent financing for the Southern Union Merger in March 2012, we terminated the 364-day Bridge Term Loan Facility. For the three months ended March 31, 2012, bridge loan related fees reflects $62.2 million representing amortization of the related commitment fees and write-off of the unamortized portion upon termination of the facility.

ETP Senior Notes

In January 2012, ETP completed a public offering of $1 billion aggregate principal amount of 5.20% Senior Notes due February 1, 2022 and $1 billion aggregate principal amount of 6.50% Senior Notes due February 1, 2042 and used the net proceeds of $1.98 billion from the offering to fund the cash portion of the purchase price of the Citrus Merger and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.

In January 2012, ETP announced a tender offer for approximately $750 million aggregate principal amount of specified series of the ETP Senior Notes. The tender offer consisted of two separate offers: an Any and All Offer and a Maximum Tender Offer. The senior notes described below were repurchased under the Any and All Offer and Maximum Tender Offer for a total cost of $885.9 million and a loss on extinguishment of debt of $115.0 million was recorded during the three months ended March 31, 2012.

In the Any and All Offer, ETP offered to purchase any and all of its 5.65% Senior Notes due August 1, 2012, at a fixed price. Pursuant to the Any and All Offer, ETP purchased $292 million aggregate principal amount of its 5.65% Senior Notes due August 1, 2012 on January 19, 2012.

In the Maximum Tender Offer, ETP offered to purchase certain series of outstanding ETP Senior Notes at a fixed spread over the index rate. Pursuant to the Maximum Tender Offer, on February 7, 2012, ETP purchased $200 million aggregate principal amount of its 9.7% Senior Notes due March 15, 2019, $200 million aggregate principal amount of its 9.0% Senior Notes due April 15, 2019 and $58.1 million aggregate principal amount of its 8.5% Senior Notes due April 15, 2014.

Revolving Credit Facilities

Parent Company Credit Agreement

As of March 31, 2012, we had no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.

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ETP Credit Facility

As of March 31, 2012, ETP had a balance of $190.0 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $2.28 billion after taking into account letters of credit of $28.3 million. The weighted average interest rate on the total amount outstanding as of March 31, 2012 was 1.74%.

Regency Credit Facility

As of March 31, 2012, there was a balance outstanding under the Regency Credit Facility of $250.0 million in revolving credit loans and approximately $11.5 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2012, which is reduced by any letters of credit, was approximately $638.5 million. The weighted average interest rate on the total amount outstanding as of March 31, 2012 was 3.09%.

Southern Union Credit Facilities

The Southern Union Credit Facility provides for a $700 million revolving credit facility which matures on May 20, 2016. Borrowings on the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union's senior unsecured notes. The annualized interest rate for the Southern Union Credit Facility was 1.86% as of March 31, 2012.

Covenants Related to Our Credit Agreements

Covenants Related to Southern Union

Southern Union is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Southern Union’s lending agreements. Covenants exist in certain of the Southern Union’s debt agreements that require Southern Union to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Southern Union to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Southern Union did not cure such default within any permitted cure period or if Southern Union did not obtain amendments, consents or waivers from its lenders with respect to such covenants.

Southern Union’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Southern Union’s debt and other financial obligations and that of its subsidiaries. Under the current credit agreements, the significant debt covenants and cross defaults are as follows:


•	Under the Southern Union Credit Facility, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65%;


•	Under the Southern Union Credit Facility, Southern Union must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;


•	Under Southern Union’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, Southern Union’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70% at the end of any calendar quarter; and


•	All of Southern Union’s major borrowing agreements contain cross-defaults if Southern Union defaults on an agreement involving at least $10 million of principal.

In addition to the above restrictions and default provisions, Southern Union and/or its subsidiaries are subject to a number of additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Southern Union’s cash management program; and limitations on Southern Union’s ability to prepay debt.

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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, 2012.


11.	REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

The Parent Company has outstanding 3,000,000 Series A Convertible Preferred Units to an affiliate of GE Energy Financial Services, Inc. having an aggregate liquidation preference of $300 million. These units are reflected as a non-current liability in our consolidated balance sheets. The Preferred Units are measured at fair value on a recurring basis. Changes in the estimated fair value of the ETE Preferred Units are recorded in other income (expense) on the consolidated statements of operations.

Regency Preferred Units

Regency had 4,371,586 Regency Preferred Units outstanding at March 31, 2012, which were convertible into 4,638,732 Regency Common Units. If outstanding on September 2, 2029, the Regency Preferred Units are mandatorily redeemable for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed quarterly cash distributions of $0.445 per unit. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s Partnership Agreement.


12.	EQUITY:

ETE Common Units Issued

The change in ETE Common Units during the three months ended March 31, 2012 was as follows:



	Number of Units
Outstanding at December 31, 2011	222,972,708
Issuance of restricted units under equity incentive plan	740
Issuance of common units in connection with Southern Union Merger (See Note 3)	56,981,860
Outstanding at March 31, 2012	279,955,308

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, 2012, we recognized decreases in partners’ capital of $14.7 million.

Sales of Common Units by ETP

During the three months ended March 31, 2012, ETP received proceeds from units issued pursuant to an Equity Distribution Agreement with Credit Suisse of $76.7 million, net of commissions, which were used for general partnership purposes. No ETP Common Units remain available to be issued under the Equity Distribution Agreement as of March 31, 2012.

For the three months ended March 31, 2012, distributions of approximately $10.6 million were reinvested under its DRIP resulting in the issuance of 238,314 ETP Common Units. As of March 31, 2012, a total of 5,158,007 ETP Common Units remain available to be issued under this agreement.

ETP issued approximately 2.25 million ETP Common Units to Southern Union as consideration for approximately $105 million in the Citrus Merger. See Note 3 for additional discussion.

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Sale of Common Units by Regency

In March 2012, Regency issued 12,650,000 Regency Common Units through a public offering. The net proceeds of approximately $297.3 million were used to repay borrowings outstanding under the Regency Credit Facility and will be used to redeem 35% in aggregate principal amount of its outstanding Senior Notes due 2016 and pay related premium expenses and interest. Regency expects to complete this redemption in May 2012.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2011:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 7, 2012	February 17, 2012	$	0.625
March 31, 2012	May 4, 2012	May 18, 2012	0.625

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2011:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 7, 2012	February 14, 2012	$	0.89375
March 31, 2012	May 4, 2012	May 15, 2012	0.89375

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2011:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 6, 2012	February 13, 2012	$	0.46
March 31, 2012	May 7, 2012	May 14, 2012	0.46

Accumulated Other Comprehensive Income

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



	March 31, 2012			December 31, 2011
Net gains on commodity related hedges	$	23,409		$	1,696
Unrealized gains on available-for-sale securities	—			114
Subtotal	23,409			1,810
Amounts attributable to noncontrolling interest	(16,839		)	(1,132		)
Total AOCI included in partners’ capital, net of tax	$	6,570		$	678


13.	UNIT-BASED COMPENSATION PLANS:

We, ETP, and Regency 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, 2012, no awards were granted to ETE employees. As of March 31, 2012 a total of 76,172 unit awards remain unvested, including the new awards granted to ETE directors during the period. We expect to recognize a total of $1.0 million in compensation expense over a weighted average period of 1.9 years related to unvested awards.

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ETP Unit-Based Compensation Plans

During the three months ended March 31, 2012, ETP employees were granted a total of 14,917 unvested awards with five-year service vesting requirements, and directors were granted a total of 2,120 unvested awards with three-year service vesting requirements. The weighted average grant-date fair value of these awards was $46.30 per unit. As of March 31, 2012 a total of 2,377,124 unit awards remain unvested, including the new awards granted during the period. ETP expects to recognize a total of $70.1 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.

Regency Unit-Based Compensation Plans

Common Unit Options

There was no Regency Common Unit Option activity for the three months ended March 31, 2012. The aggregate intrinsic value and weighted average contractual term in years as of March 31, 2012 for the outstanding and exercisable common unit options was $0.5 million and 4.1,years respectively. During the three months ended March 31, 2011, Regency received $0.5 million in proceeds from the exercise of unit options.

Phantom Units

During the three months ended March 31, 2012, Regency employees and directors were granted 4,000 Regency phantom units with three-year service vesting requirements. As of March 31, 2012, a total of 1,061,404 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.56. Regency expects to recognize a total of $19.1 million in compensation expense over a weighted average period of 4.1 years related to Regency’s unvested phantom units.


14.	BENEFITS:

Southern Union has pension plans that cover substantially all of its distribution operations' employees. Normal retirement age is 65, but certain plan provisions allow for earlier retirement. Pension benefits are calculated under formulas principally based on average earnings and length of service for salaried and non-union employees and average earnings and length of service or negotiated non-wage based formulas for union employees.

Southern Union has other postretirement plans that cover most of its employees. The health care plans generally provide for cost sharing between Southern Union and its retirees in the form of retiree contributions, deductibles, coinsurance, and a fixed cost cap on the amount Southern Union pays annually to provide future retiree health care coverage under certain of these plans.

Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the acquisition date (March 26, 2012) about the obligations and funded status of Southern Union’s pension and other postretirement plans on a combined basis:



	Pension Benefits			Other Postretirement Benefits
Benefit obligation	$	227,548		$	140,651
Fair value of plan assets	$	143,979		$	118,784
Amount underfunded	$	(83,569	)	$	(21,867	)
Amounts recognized in our consolidated balance sheet related to Southern Union's pension and other postretirement plans consist of:
Non-current assets	$	—		$	6,062
Current liabilities	—			(133		)
Non-current liabilities	(83,569		)	(27,796		)
	$	(83,569	)	$	(21,867	)

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The following table summarizes information at the acquisition date (March 26, 2012) for plans with an accumulated benefit obligation in excess of the plan assets:



	Pension Benefits		Other Postretirement Benefits
Projected benefit obligation	$	227,548	N/A
Accumulated benefit obligation	213,614		$	110,314
Fair value of plan assets	143,979		82,385

Assumptions

The following table includes weighted average assumptions used in determining benefit obligations as of the acquisition date (March 26, 2012):



	Pension Benefits		Other Postretirement Benefits
Discount rate	4.10	%	4.10	%
Rate of compensation increase	3.03	%	N/A

The assumed health care cost trend rates used to measure the expected cost of benefits covered by Southern Union's other postretirement benefit plans as of the acquisition date (March 26, 2012) are shown in the table below:



Health care cost rend rate assumed for next year	9.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.85	%
Year that the rate reaches the ultimate trend rate	2020

Defined Contribution Plan

Employees of Southern Union and its subsidiaries participate in a company-sponsored defined contribution savings plan that is substantially similar to the 401(k) savings plan that covers the employees of ETE, ETP and Regency.


15.	INCOME TAXES:

The components of the federal and state income tax expense of our taxable subsidiaries are summarized as follows:



	Three Months Ended March 31,
	2012			2011
Current expense (benefit):
Federal	$	(19	)	$	5,102
State	3,736			3,996
Total	3,717			9,098
Deferred expense (benefit):
Federal	(8,565		)	188
State	6,427			617
Total	(2,138		)	805
Total income tax expense	$	1,579		$	9,903

Our effective tax rate has historically differed from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level. The acquisition of Southern Union on March 26, 2012 is expected to increase our overall effective rate going forward, because Southern Union is subject to federal and state income taxes.

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In connection with the Southern Union Merger, we recorded a net deferred tax liability of approximately $1.77 billion, which was primarily related to property, plant and equipment. Southern Union has deferred tax net operating loss carry forwards of approximately $65 million as of March 31, 2012, of which $15 million and $50 million expire in 2030 and 2031, respectively.

As of March 31, 2012, Southern Union has unrecognized tax benefits for capitalization policies and state filing positions of $2.3 million and $17.1 million, respectively, which relate to tax positions taken by Southern Union or its subsidiaries prior to our acquisition on March 26, 2012.


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

Regulatory Matters

Southern Union and its Subsidiaries

Sea Robin Pipeline, a subsidiary of Southern Union, is recovering Hurricane Ike-related costs not otherwise recovered from insurance proceeds or from other third parties, as well as applicable carrying charges, through a rate surcharge approved by the FERC. As of March 31, 2012, our consolidated balance sheet reflects approximately $44.8 million of costs to be recovered by Sea Robin Pipeline in future periods via the surcharge.

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 to present and is expected to take approximately one year to complete.

Contingent Residual Support Agreement — AmeriGas

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 Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes.

In connection with the Propane Contribution, 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.

Commitments

In the normal course of our business, our operating entities purchase, process and sell natural gas pursuant to long-term contracts and 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 2029. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $6.7 million and $5.4 million for the three months ended March 31, 2012 and 2011, respectively.

Future minimum lease commitments for such leases are:



Years Ending December 31:
2012 (remainder)	$	26,491
2013	37,990
2014	33,192
2015	31,708
2016	30,770
Thereafter	211,600

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.

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Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and NGLs are flammable, combustible gases. 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.

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, 2012 and December 31, 2011, accruals of approximately $28.3 million and $18.2 million, respectively, were reflected on our consolidated 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 the resolution of a particular contingency based on changes in facts and circumstances or in the expected outcome.

No amounts have been recorded in our March 31, 2012 or December 31, 2011 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Following is a discussion or our legal proceedings:

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.

Attorney General of the Commonwealth of Massachusetts v New England Gas Company. On July 7, 2011, the Massachusetts Attorney General filed a regulatory complaint with the MDPU against New England Gas Company with respect to certain environmental cost recoveries. The Attorney General 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 Attorney General 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 $18.5 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 current Vice Chairman, President and COO, 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 Attorney General contends only would 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 Attorney General’s motion to be reimbursed for 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.

Air Quality Control. SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ.

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Compliance Orders from the New Mexico Environmental Department. SUGS has been in discussions with the New Mexico Environmental Department concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. The New Mexico Environmental Department has issued amended compliance orders and proposed penalties for alleged violations at Jal #4 in the amount of $0.5 million and at Jal #3 in the amount of $5.5 million. Hearings on the compliance orders were delayed until September 2012 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the New Mexico Environmental Department claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded an accrued liability and will continue to assess its potential exposure to the allegations as the matter progresses.

FGT Phase VIII Expansion. FGT Phase VIII Expansion project was placed in-service on April 1, 2011, at an approximate cost of $2.5 billion, including capitalized equity and debt costs. To date, FGT has entered into long-term firm transportation service agreements with shippers for 25-year terms accounting for approximately 74% of the available expansion capacity.

In 2011, CrossCountry and Citrus' other stockholder each made sponsor contributions of $37 million in the form of loans to Citrus, net of repayments. The contributions are related to the costs of FGT's Phase VIII Expansion project. In conjunction with anticipated sponsor contributions, Citrus has entered into a promissory note in favor of each stockholder for up to $150 million. The promissory notes have a final maturity date of March 31, 2014, with no principal payments required prior to the maturity date, and bear an interest rate equal to a one-month Eurodollar rate plus a credit spread of 1.5%. Amounts may be redrawn periodically under the notes to temporarily fund capital expenditures, debt retirements, or other working capital needs.

FGT Pipeline Relocation Costs. The FDOT/FTE has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGT's mainline pipelines located in FDOT/FTE rights-of-way. Several FDOT/FTE projects are the subject of litigation in Broward County, Florida. On January 27, 2011, a jury awarded FGT $82.7 million and rejected all damage claims by the FDOT/FTE. On May 2, 2011, the judge issued an order entitling FGT to an easement of 15 feet on either side of its pipelines and 75 feet of temporary work space. The judge further ruled that FGT is entitled to approximately $8 million in interest. In addition to ruling on other aspects of the easement, he ruled that pavement could not be placed directly over FGT's pipeline without the consent of FGT although FGT would be required to relocate the pipeline if it did not provide such consent. He also denied all other pending post-trial motions. The FDOT/FTE filed a notice of appeal on July 12, 2011. Briefing to the Florida Fourth District Court of Appeals is complete. The Florida Fourth District Court of Appeals granted a request by the FDOT to expedite the appeal. Oral argument was held March 7, 2012. Amounts ultimately received would primarily reduce FGT's property, plant and equipment costs.

W. J. Garrett Trust. On November 28, 2011, W.J. Garrett Trust filed a lawsuit in Texas state court derivatively and on behalf of ETP unitholders. This lawsuit is W.J. Garrett Trust, et al. v. Bill W. Byrne, Paul E. Glaske, Kelcy L. Warren, David R. Albin, Michael K. Grimm, Ted Collins, Jr., Ray C. Davis, Marshall S. McCrea III, K. Rick Turner, ETE, Southern Union, ETP GP, ETP LLC and ETP, case number 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiff alleges a variety of causes of action challenging the Citrus Acquisition and ETP's divesture of its Propane Business to Amerigas (the “Propane Transactions”). Specifically, plaintiff alleges that the Propane Transactions involved an unfair price and alleges several deficiencies in the process by which the named directors and officers are conducting the Propane Transactions. Additionally, plaintiff alleges that: (i) the named directors and officers breached their fiduciary duties and their contractual duties in connection with the Propane Transactions; (ii) the named entities aided and abetted these breaches of the directors' and officers' fiduciary and contractual duties; (iii) Southern Union and ETE tortiously interfered with ETP's partnership agreement; and (iv) the defendants conspired to breach fiduciary and contractual duties. Plaintiff also seeks a declaration that the defendant breached their fiduciary and contractual duties.

On January 30, 2012, defendants filed a motion to stay discovery and special exceptions challenging the sufficiency of plaintiff's claims. On March 5, 2012, Judge Reece Rondon of the 234th Judicial District Court of Harris County, Texas (the state court judge originally assigned the case) heard oral argument on defendants' motions. Immediately following the hearing, Judge Rondon recused himself and transferred the case to Judge Randy Wilson of the 157th Judicial District Court of Harris County, Texas. On April 3, 2012, Judge Wilson heard oral argument on defendants' motions and the parties are awaiting ruling from the court on the motions.

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El Paso. CrossCountry, the Southern Union subsidiary that indirectly owns a 50% interest in Citrus, filed a petition in the Delaware Court of Chancery seeking a declaratory judgment against El Paso, the owner of the other 50% interest of Citrus, that the Citrus Merger did not breach El Paso's rights under a joint venture agreement related to Citrus. This petition was filed by CrossCountry following an exchange of letters between CrossCountry, El Paso and Southern Union in which El Paso stated that it believed the Citrus Merger violated the provisions of the joint venture agreement. Subsequently, El Paso filed a petition asserting a counterclaim action against CrossCountry, ETP and ETE based on its claim that the Citrus Merger violated El Paso's right of first refusal and, in such petition, El Paso sought a rescission of the Citrus Merger or, alternatively, damages.

On April 18, 2012, the parties to the declaratory judgment action and related counterclaim action entered into a joint stipulation pursuant to which El Paso agreed that the Citrus Merger did not breach the joint venture agreement and that El Paso was not entitled to rescission or damages with respect to the Citrus Merger. On April 20, 2012, the Delaware court granted an order approving the joint stipulation and, as a result, all litigation with respect to the Citrus Merger has been terminated.

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.

Our subsidiaries have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.

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 subsidiaries' liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future.

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 CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require some of our subsidiaries 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 a 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.

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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 some of our subsidiaries to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if equipment is replaced or existing facilities are expanded 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 our subsidiaries might make in the future.

On April 17, 2012 the EPA issued the Oil and Natural Gas Sector New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants. The standards revise the new source performance standards for volatile organic compounds from leaking components at onshore natural gas processing plants and new source performance standards for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by the existing standards. In addition to the operations covered by the existing standards, the newly established standards regulate volatile organic compound emissions from gas wells, centrifugal compressors, reciprocating compressors, pneumatic controllers and storage vessels. ETP is reviewing the new standards to determine the impact on its operations.

Our subsidiaries' 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 our subsidiaries to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

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 MGPs and may also be responsible for the removal of old MGP structures.

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, 2012		December 31, 2011
Current	$	8,577	$	3,861
Non-current	23,341		9,990
Total environmental liabilities	$	31,918	$	13,851

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17.	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

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

ETP

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price. ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities.). At the inception of the hedge, ETP will 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 ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP will value the hedged natural gas inventory at current spot market prices along with the financial derivative it uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of its derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that it recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.

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

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

Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by its long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. To the extent that financial contracts are not tied to physical delivery volumes, ETP may engage in offsetting financial contracts to balance its positions. To the extent open commodity positions exist, fluctuating commodity prices can impact its financial position and results of operations, either favorably or unfavorably.

ETP uses propane futures contracts to secure the purchase price of its propane inventory for a percentage of the anticipated sales by its cylinder exchange business. Prior to the deconsolidation of the Propane Business, ETP also used propane futures contracts to fix the purchase price related to certain fixed price sales contracts.

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



	March 31, 2012			December 31, 2011
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX⁽¹⁾	11,280,000		2012-2013	(151,260,000	)	2012-2013
Power (Thousand Megawatt):
Forwards	(1,000	)	2012-2013	—		—
Options — Calls	84		2012	—		—
Options — Puts	32		2012	—		—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(43,882,500	)	2012-2013	(61,420,000	)	2012-2013
Swing Swaps IFERC	(62,117,500	)	2012-2013	92,370,000		2012-2013
Fixed Swaps/Futures	(2,042,500	)	2012-2013	797,500		2012
Forward Physical Contracts	(43,604,214	)	2012	(10,672,028	)	2012
Propane (Gallons):
Forwards/Swaps	6,571,500		2012-2013	38,766,000		2012-2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(25,920,000	)	2012-2013	(28,752,500	)	2012
Fixed Swaps/Futures	(55,690,000	)	2012-2013	(45,822,500	)	2012
Hedged Item — Inventory	55,690,000		2012	45,822,500		2012
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(17,400,000	)	2012-2013	—		—
Fixed Swaps/Futures	(35,650,000	)	2012-2013	—		—
Options — Puts	2,700,000		2012	3,600,000		2012
Options — Calls	(2,700,000	)	2012	(3,600,000	)	2012

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

We expect gains of $19.9 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.

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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.

Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Audit and Risk Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.

Regency’s Preferred Units (see Note 11) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to effect its cash flows.

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



	March 31, 2012		December 31, 2011
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	2,838,000	2012-2013	—	—
Propane (Gallons):
Forwards/Swaps	10,584,000	2012-2013	—	—
Natural Gas Liquids (Barrels):
Forwards/Swaps	435,000	2012-2013	—	—
Options — Puts	110,000	2012	110,000	2012
WTI Crude Oil (Barrels):
Forwards/Swaps	401,000	2012-2014	—	—
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	—	—	2,198,000	2012
Propane (Gallons):
Forwards/Swaps	—	—	11,802,000	2012-2013
Natural Gas Liquids (Barrels):
Forwards/Swaps	—	—	533,000	2012-2013
WTI Crude Oil (Barrels):
Forwards/Swaps	—	—	350,000	2012-2014

On January 1, 2012, Regency de-designated all of its swap contracts and has accounted for these contracts using mark-to-market accounting. As of March 31, 2012, Regency had $1.1 million in net hedging losses in AOCI which will be amortized to earnings over the next 2 years, of which $1.5 million will be reclassified into earnings over the next 12 months.

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Southern Union

Southern Union is exposed to certain risks in its ongoing business operations. Natural gas and NGL price swaps and NGL processing spread swaps are the principal derivative instruments used by Southern Union to manage commodity price risk associated with purchases and/or sales of natural gas and/or NGL, although other commodity derivative contracts may also be used from time to time.

Southern Union primarily enters into natural gas and NGL price swaps and NGL processing spread swaps to manage its exposure to changes in margin on forecasted sales of equity natural gas and NGL volumes resulting from movements in market commodity prices.

Southern Union enters into natural gas commodity financial instruments to manage the exposure to changes in the cost of natural gas passed through to utility customers that result from movements in market commodity prices. The cost of the derivative instruments and settlement of the respective obligations are recovered from utility customers through the purchased natural gas adjustment clause as authorized by the applicable regulatory authority and therefore do not impact earnings.

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



	March 31, 2012
	Notional Volume	Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	21,920,000	2012-2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	2,750,000	2012
Natural Gas Liquids (Barrels):
Fixed Swaps/Futures	1,170,675	2012

We expect net after-tax gains of $1.1 million related to Southern Union’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.

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Interest Rate Risk

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and floating rate debt. We manage our current 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 is a summary of interest rate swaps outstanding as of March 31, 2012 and December 31, 2011, none of which were designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

March 31, 2012

December 31, 2011

ETE

March 2017

Pay a fixed rate of 1.27% and receive a floating rate

375,000

—

ETP

May 2012 ⁽²⁾

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

—

350,000

ETP

August 2012⁽²⁾

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

—

500,000

ETP

July 2013 ⁽²⁾

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

400,000

300,000

ETP

July 2014 ⁽²⁾

Forward starting to pay a fixed rate of 4.26% and receive a floating rate

400,000

—

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600,000

500,000

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

250,000

Southern Union

November 2021

Pay a fixed rate of 3.746% and receive a floating rate

450,000

N/A

Southern Union

November 2016

Pay a fixed rate of 2.913% and receive a floating rate

75,000

N/A

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


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

As of March 31, 2012, Southern Union had no outstanding treasury rate locks; however, certain of its treasury rate locks that settled in prior periods are associated with interest payments on outstanding long-term debt. These treasury rate locks are accounted for as cash flow hedges, with the effective portion of their settled value recorded in AOCI and reclassified into interest expense in the same periods during which the related interest payments on long-term debt impact earnings.

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 have 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 $62.0 million and $66.2 million as of March 31, 2012 and December 31, 2011, respectively.

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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. The aggregate fair value of Southern Union's derivative instruments with credit-risk-related contingent features that are in a net liability position at March 31, 2012 was $21.4 million.

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 balance sheet overview of consolidated derivative assets and liabilities as of March 31, 2012 and December 31, 2011:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2012		December 31, 2011		March 31, 2012			December 31, 2011
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	58,103	$	77,197	$	(486	)	$	(819	)
Commodity derivatives	6,635		4,539		(310		)	(10,128		)
	64,738		81,736		(796		)	(10,947		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	187,403	$	227,337	$	(211,638	)	$	(251,268	)
Commodity derivatives	20,560		1,017		(56,704		)	(4,844		)
Interest rate derivatives	36,550		36,301		(157,544		)	(117,490		)
Embedded derivatives in Regency Preferred Units	—		—		(38,553		)	(39,049		)
	244,513		264,655		(464,439		)	(412,651		)
Total derivatives	$	309,251	$	346,391	$	(465,235	)	$	(423,598	)

The commodity derivatives (margin deposits) are recorded in other current assets on our consolidated balance sheets. The remainder of the non-exchange traded financial derivative instruments are recorded at fair value as price risk management assets or price risk management liabilities and are classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to consolidated derivative financial instruments for the periods presented:



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended March 31,
	2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	22,215	$	(10,892	)
Total	$	22,215	$	(10,892	)

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	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,
		2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	3,435	$	13,539
Total		$	3,435	$	13,539



	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
		Three Months Ended March 31,
		2012		2011
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	47	$	92
Total		$	47	$	92



	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,
		2012			2011
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(12,838	)	$	6,417
Total		$	(12,838	)	$	6,417



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2012			2011
Derivatives not designated as hedging instruments:
Commodity derivatives — Trading	Cost of products sold	$	(10,586	)	$	—
Commodity derivatives — Non-Trading	Cost of products sold	(463		)	8,006
Interest rate derivatives	Gains on non-hedged interest rate derivatives	27,490			1,520
Embedded derivatives	Other income	496			2,575
Total		$	16,937		$	12,101

We recognized $17.9 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the three months ended March 31, 2011. In addition, we recognized unrealized losses of $86.2 million and $8.9 million on commodity derivatives and related hedged inventory accounted for as fair value hedges for the three months ended March 31, 2012 and 2011, respectively.

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18.	RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. For the three months ended March 31, 2012 and 2011, the Parent Company received $4.3 million and $4.8 million in service fees, respectively, from Regency related to these services. For the three months ended March 31, 2012 and 2011, the Parent Company paid $4.4 million and $4.9 million in service fees, respectively, to ETP related to these services and other services for ETE's benefit. The service fees received from Regency for the three months ended March 31, 2012 and 2011 reflect the reimbursement of various general and administrative services of $1.8 million and $2.3 million, respectively, for expenses incurred by ETP on behalf of Regency.

Under a master services agreement with HPC, Regency operates HPC, providing all employees and services for its operation and management. The related party general administrative expenses reimbursed to Regency were $4.2 million for the three months ended March 31, 2012 and 2011.


19.	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, 2012		December 31, 2011
Deposits paid to vendors	$	102,028	$	66,231
Prepaid expenses and other	122,142		115,673
Total other current assets	$	224,170	$	181,904

Other Non-Current Assets, net

Other non-current assets, net consisted of the following:



	March 31, 2012		December 31, 2011
Unamortized financing costs (3 to 30 years)	$	161,464	$	132,375
Regulatory assets	224,494		88,993
Other	104,346		27,542
Total other non-current assets, net	$	490,304	$	248,910

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	March 31, 2012		December 31, 2011
Interest payable	$	289,598	$	204,182
Customer advances and deposits	35,925		100,525
Accrued capital expenditures	233,660		228,877
Accrued wages and benefits	57,428		80,205
Taxes payable other than income taxes	56,068		79,331
Income taxes payable	55,565		14,781
Other	220,415		56,011
Total accrued and other current liabilities	$	948,659	$	763,912

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20.	REPORTABLE SEGMENTS:

Our reportable segments include reportable segments for our investments in ETP and Regency, which reflect the consolidated operations of ETP and Regency.

Each of the respective general partners of ETP and Regency has separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. See further discussion of ETP and Regency’s operations in Note 1.

We evaluate the performance of our reportable segments by their net income. The following tables present financial information by reportable segment. The amounts reflected as “Corporate and Other” include (i) the Parent Company activity, (ii) 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 (iii) the operating results of Southern Union from the date of acquisition (March 26, 2012) to March 31, 2012.

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

The following tables present the financial information by segment for the following periods:



	Investment in ETP		Investment in Regency			Corporate and Other ⁽¹⁾			Adjustments and Eliminations			Total
Three months ended March 31, 2012:
Revenues from external customers	$	1,301,543	$	353,933		$	36,671		$	(3,016	)	$	1,689,131
Intersegment revenues	4,317		3,966			—			(8,283		)	—
Income tax expense (benefit)	14,123		51			(12,595		)	—			1,579
Net income (loss)	1,126,097		28,900			(182,331		)	(11,364		)	961,302
Three months ended March 31, 2011:
Revenues from external customers	$	1,676,047	$	315,559		$	—		$	(2,486	)	$	1,989,120
Intersegment revenues	11,530		1,693			—			(13,223		)	—
Income tax expense (benefit)	10,597		(32		)	(662		)	—			9,903
Net income (loss)	247,202		14,305			(62,415		)	—			199,092

⁽¹⁾ The Corporate and Other column includes the results of operations of Southern Union from the date of acquisition (March 26, 2012) to March 31, 2012.



	March 31, 2012			December 31, 2011
Total assets:
Investment in ETP	$	17,407,790		$	15,518,616
Investment in Regency	5,719,645			5,567,856
Southern Union:
Transportation & Storage	5,890,054			—
Gathering & Processing	2,730,322			—
Distribution	1,260,397			—
Corporate and Other	526,857			470,086
Adjustments and Eliminations	(712,964		)	(659,765		)
Total	$	32,822,101		$	20,896,793

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

Investment in ETP



	Three Months Ended March 31,
	2012		2011
Intrastate Transportation and Storage	$	446,796	$	588,678
Interstate Transportation	128,276		105,101
Midstream	454,099		413,195
NGL Transportation and Services	154,268		—
Retail Propane and Other Retail Propane Related	80,006		557,215
All Other	42,415		23,388
Total revenues	1,305,860		1,687,577
Less: Intersegment revenues	4,317		11,530
Revenues from external customers	$	1,301,543	$	1,676,047

Investment in Regency



	Three Months Ended March 31,
	2012		2011
Gathering and Processing	$	307,167	$	265,972
Joint Ventures	—		—
Contract Compression	37,201		38,436
Contract Treating	9,135		8,433
Corporate and Others	4,396		4,411
Total revenues	357,899		317,252
Less: Intersegment revenues	3,966		1,693
Revenues from external customers	$	353,933	$	315,559

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21.	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, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	57,354	$	18,460
Accounts receivable from related companies	3,696		1,456
Note receivable from related company	221,217		—
Other current assets	624		714
Total current assets	282,891		20,630
ADVANCES TO AND INVESTMENTS IN AFFILIATES	6,259,072		2,225,572
LONG-TERM PRICE RISK MANAGEMENT ASSETS	2,552		—
GOODWILL	11,462		—
OTHER NON-CURRENT ASSETS, net	63,270		49,906
Total assets	$	6,619,247	$	2,296,108
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	240	$	174
Accounts payable to related companies	17,771		12,334
Interest payable	69,028		34,753
Price risk management liabilities	2,949		—
Accrued and other current liabilities	5,379		953
Total current liabilities	95,367		48,214
LONG-TERM DEBT, less current maturities	3,760,000		1,871,500
SERIES A CONVERTIBLE PREFERRED UNITS	326,950		322,910
OTHER NON-CURRENT LIABILITIES	11,462		—
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL:
General Partner	357		321
Limited Partners	2,418,541		52,485
Accumulated other comprehensive income	6,570		678
Total partners’ capital	2,425,468		53,484
Total liabilities and partners' capital	$	6,619,247	$	2,296,108

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended March 31,
	2012			2011
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(31,075	)	$	(1,842	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(42,587		)	(40,939		)
Bridge loan related fees	(62,241		)	—
Loss on non-hedged derivatives	(397		)	—
Equity in earnings of affiliates	306,687			146,642
Other, net	(3,901		)	(15,159		)
INCOME BEFORE INCOME TAXES	166,486			88,702
Income tax expense	64			62
NET INCOME	166,422			88,640
GENERAL PARTNER’S INTEREST IN NET INCOME	506			274
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	165,916		$	88,366

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STATEMENTS OF CASH FLOWS

(unaudited)



	Three Months Ended March 31,
	2012			2011
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	146,211		$	151,609
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions	(1,558,377		)	—
Note receivable from related company	(221,217		)	—
Net cash used in investing activities	(1,779,594		)	—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	1,960,000			—
Principal payments on debt	(71,500		)	—
Distributions to partners	(139,791		)	(120,763		)
Debt issuance costs	(76,432		)	—
Net cash provided by (used in) financing activities	1,672,277			(120,763		)
INCREASE IN CASH AND CASH EQUIVALENTS	38,894			30,846
CASH AND CASH EQUIVALENTS, beginning of period	18,460			27,247
CASH AND CASH EQUIVALENTS, end of period	$	57,354		$	58,093

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

AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in thousands)

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, 2011 filed with the SEC on February 22, 2012. Additionally, Energy Transfer Partners, L.P., Regency Energy Partners LP and Southern Union Company electronically file certain documents with the SEC, including annual reports on Form 10-K and quarterly reports on Form 10-Q. The SEC file number for each registrant and company website address is as follows:


•	ETP — SEC File No. 1-11727; website address: www.energytransfer.com


•	Regency — SEC File No. 0-51757; website address: www.regencyenergy.com


•	Southern Union — SEC File No. 01-06407; website address: www.sug.com

The information on these websites is not incorporated by reference into this report.

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to a variety of risks, uncertainties and assumptions. 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, 2011 and in “Part II — Other Information – Item 1A. Risk Factors” of this report.

OVERVIEW

We directly and indirectly own equity interests in entities that are engaged in diversified energy-related services. At March 31, 2012, our interests in ETP and Regency consisted of:



	General Partner Interest (as a % of total partnership interest)		IDRs		Common Units	Total Ownership (as a % and net of any treasury units)
ETP	1.5	%	100	%	52,476,059	24	%
Regency	1.6	%	100	%	26,266,791	17	%

Prior to the Southern Union Merger, the Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. Effective with the acquisition of Southern Union, the Parent Company also generates cash flows through its wholly-owned subsidiary, Southern Union. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. The Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries.

The following is a brief description of our operating entities:

•

ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% interest in Lone Star, a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. Concurrent with the Parent Company's acquisition of Southern Union, ETP acquired a 50% interest in Citrus, which owns FGT.

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•

Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating, transportation, fractionation and storage of natural gas and 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, and Marcellus shales, as well as the Permian Delaware basin. Its assets are located in California, Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

•

Recent Developments

Following is a brief discussion of our significant recent developments:

Parent Company


•	We completed the acquisition of Southern Union on March 26, 2012 for approximately $3.01 billion in cash and approximately 57.0 million ETE Common Units valued at $2.35 billion at the time of the merger.

•

We obtained a $2.0 billion Senior Secured Term Loan as permanent financing to fund a portion of the cash consideration of the Southern Union Merger and pay related fees and expenses, including existing borrowings under our revolving credit facility and for general partnership purposes. We also used a portion of the cash received from ETP in the Citrus Merger (discussed below) to fund the remaining cash portion of the Southern Union Merger.

ETP

•

In January 2012, ETP contributed its Propane Business to AmeriGas in exchange for approximately $1.46 billion in cash and approximately 29.6 million AmeriGas Common Units valued at $1.12 billion at the time of the contribution. AmeriGas also assumed approximately $71 million of existing HOLP debt. Consideration received in this transaction was used to fund ETP's tender offer and other purposes, as discussed below.


•	In January 2012, ETP issued $2.0 billion principal amount of senior notes, the proceeds from which were used to fund the cash potion of the Citrus Merger described below and for general partnership purposes.


•	In February 2012, ETP completed the repurchase of approximately $750 million of its senior notes.

•

On March 26, 2012, in connection with the Southern Union Merger, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owns an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.25 million ETP Common Units that are now held by Southern Union. This acquisition provides ETP with access to the Florida market through FGT.


•	On April 30, 2012, ETP entered into an agreement to acquire Sunoco in a Common Unit and cash transaction for total consideration of $5.3 billion as discussed below.

Regency

•

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Pending Sunoco Merger

On April 30, 2012, ETP announced its entry into a definitive merger agreement whereby it will acquire Sunoco Inc. in a common unit and cash transaction valued at $5.3 billion based on ETP's closing unit price on April 27, 2012. Under the terms of the merger agreement, Sunoco shareholders would receive, for each Sunoco common share, either $50.00 in cash, 1.049 ETP Common Units or a combination of $25.00 in cash and 0.5245 ETP Common Units. The aggregate cash paid and ETP Common Units issued will be capped so that the cash and ETP Common Units will each represent 50% of the aggregate consideration. Upon closing, Sunoco shareholders are expected to own approximately 20% of ETP's outstanding limited partner interests. This transaction is expected to close in the third or fourth quarter of 2012, subject to approval of Sunoco's shareholders and customary regulatory approvals.

Results of Operations

Consolidated Results



	Three Months Ended March 31,
	2012			2011			Change
Revenues	$	1,689,131		$	1,989,120		$	(299,989	)
Cost of products sold	1,022,200			1,201,426			(179,226		)
Gross margin	666,931			787,694			(120,763		)
Operating expenses	174,905			220,696			(45,791		)
Depreciation and amortization	161,201			139,256			21,945
Selling, general and administrative	148,262			63,499			84,763
Operating income	182,563			364,243			(181,680		)
Interest expense, net of interest capitalized	(213,330		)	(167,929		)	(45,401		)
Bridge loan related fees	(62,241		)	—			(62,241		)
Equity in earnings of affiliates	75,232			25,441			49,791
Gain on deconsolidation of Propane Business	1,055,944			—			1,055,944
Losses on disposal of assets	(1,060		)	(1,754		)	694
Loss on extinguishment of debt	(115,023		)	—			(115,023		)
Gains on non-hedged interest rate derivatives	27,490			1,520			25,970
Other, net	13,306			(12,526		)	25,832
Income tax expense	(1,579		)	(9,903		)	8,324
Net income	$	961,302		$	199,092		$	762,210

Changes reflected above between the three months ended March 31, 2012 and 2011 are primarily attributable to changes within our Investment in ETP and Investment in Regency segments (as discussed in “Segment Operating Results” below), except as noted in the discussion that follows.

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Operating Income. The changes between periods in the individual components of operating income are primarily attributable to changes within our Investment in ETP and Investment in Regency segments, as described in the “Segment Operating Results” section below. In addition, we also experienced increases in the operating income line items due to the consolidation of Southern Union from the date of the Southern Union Merger (March 26, 2012) to March 31, 2012. Selling, general and administrative expenses for the three months ended March 31, 2012 also reflected $29.9 million of costs related to the Southern Union Merger.

Interest Expense. Interest expense increased primarily due to increases in interest expense for ETP and Regency of $29.6 million and $9.6 million, respectively, as discussed in “Segment Operating Results” below, and also reflected interest expense of $4.4 million incurred by Southern Union from the date of the Southern Union Merger through March 31, 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.

Other, net. In addition to the changes discussed in the “Segment Operating Results” section below, the increase also reflected an increase of approximately $11.0 million related to the change in the estimated fair value of the ETE Preferred Units.

Income Tax Expense. We experienced a favorable change in income tax expense primarily due to income tax benefits recorded by Southern Union from the date of the Southern Union Merger (March 26, 2012) through March 31, 2012.

Supplemental Pro Forma Analysis

The following unaudited pro forma consolidated results of operations for the three months ended March 31, 2012 are presented as if the Southern Union Merger had been completed on January 1, 2012:



	Three Months Ended March 31, 2012
	Actual		Pro Forma
Revenues	$	1,689,131	$	2,322,780
Net income	961,302		969,641
Net income attributable to partners	166,422		173,070
Basic net income per Limited Partner unit	$	0.73	$	0.61
Diluted net income per Limited Partner unit	$	0.73	$	0.61

The pro forma consolidated results of operations include adjustments to:


•	include the results of Southern Union for all periods presented;


•	include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;


•	include incremental interest expense related to financing the transactions;


•	adjust for one-time expenses; and


•	adjust for relative changes in ownership resulting from the transactions.

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

Segment Operating Results

Our reportable segments reflect two reportable segments, which conduct their business exclusively in the United States of America, as follows:


•	Investment in ETP — Reflects the consolidated operations of ETP.


•	Investment in Regency — Reflects the consolidated operations of Regency.

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

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We evaluate the performance of our reportable segments by their net income. The following table presents our performance measure by reportable segment. The amounts reflected as “Corporate and Other” include (i) the Parent Company activity, (ii) 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 (iii) the operating results of Southern Union from the date of acquisition (March 26, 2012) to March 31, 2012.

Net income by reportable segment is as follows:



	Three Months Ended March 31,
	2012			2011			Change
Investment in ETP	$	1,126,097		$	247,202		$	878,895
Investment in Regency	28,900			14,305			14,595
Corporate and Other ⁽¹⁾	(182,331		)	(62,415		)	(119,916		)
Adjustments and Eliminations	(11,364		)	—			(11,364		)
Net income	$	961,302		$	199,092		$	762,210

⁽¹⁾ The Corporate and Other column includes the results of operations of Southern Union from the date of acquisition (March 26, 2012) to March 31, 2012.

Investment in ETP



	Three Months Ended March 31,
	2012			2011			Change
Revenues	$	1,305,860		$	1,687,577		$	(381,717	)
Cost of products sold	773,485			994,457			(220,972		)
Gross margin	532,375			693,120			(160,745		)
Operating expenses	127,990			188,489			(60,499		)
Depreciation and amortization	101,917			95,964			5,953
Selling, general and administrative	48,523			45,532			2,991
Operating income	253,945			363,135			(109,190		)
Interest expense, net of interest capitalized	(136,820		)	(107,240		)	(29,580		)
Equity in earnings of affiliates	54,625			1,633			52,992
Gain on deconsolidation of Propane Business	1,055,944			—			1,055,944
Losses on disposal of assets	(1,024		)	(1,726		)	702
Loss on extinguishment of debt	(115,023		)	—			(115,023		)
Gains on non-hedged interest rate derivatives	27,895			1,779			26,116
Other, net	678			218			460
Income tax expense	(14,123		)	(10,597		)	(3,526		)
Net income	$	1,126,097		$	247,202		$	878,895

Gross Margin. ETP's gross margin decreased primarily due to the deconsolidation of ETP's Propane Business. Gross margin from retail propane sales were approximately $210.5 million lower during the three months ended March 31, 2012 compared to the same period in the prior year because ETP's Propane Business was deconsolidated upon completion of the contribution transaction with AmeriGas. The gross margin decrease that resulted from the deconsolidation of the Propane Business was partially offset by an increase in gross margin of $68.9 million from ETP's NGL transportation and services operations, which began operations in May 2011 in connection with the acquisition of LDH.

Operating Expenses. ETP's operating expenses decreased $70.2 million in its retail propane and other retail propane related operations as a result of ETP's contribution of its Propane Business to AmeriGas in January 2012.

Depreciation and Amortization. ETP's depreciation and amortization increased primarily due to its recent acquisition and assets placed in service partially offset by a decrease as the result of the contribution of the Propane Business in January 2012.

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Selling, General and Administrative. ETP’s selling, general and administrative expenses increased primarily as a result of NGL transportation and services operations since ETP's acquisition of LDH in May of 2011 in addition to increases in employee related costs among its other operations. These increases were partially offset by a decrease in selling, general and administrative expenses in ETP's retail propane and other retail propane operations as a result of its contribution of its Propane Business to AmeriGas in January 2012.

Interest Expense. ETP's interest expense increased for the three months ended March 31, 2012 principally due to the issuance of $1.5 billion of senior notes in May 2011 to fund the acquisition of LDH and the issuance of $2 billion of senior notes in January 2012 to fund the Citrus Merger. While ETP's interest expense increased as a result of the overall increase in the amount of long-term debt outstanding, the incremental interest from the new senior notes was partially offset by a reduction of a series of its comparatively higher coupon notes which were repurchased in the tender offers that were completed in January 2012.

Equity in Earnings of Affiliates. As a result of ETP's contribution of its Propane Business to AmeriGas, ETP received an equity investment in AmeriGas and recorded equity in earnings of approximately $39.4 million for the three months ended March 31, 2012, which represents ETP's proportionate share of AmeriGas' net income. ETP also recorded equity in earnings of Citrus of $1.0 million for the period from acquisitions (March 26, 2012) through March 31, 2012 and an increase of equity in earnings of FEP of $13.1 million.

Gain on Deconsolidation of Propane Business. A gain on deconsolidation was recorded as a result of ETP's contribution of its Propane Business to AmeriGas in January 2012.

Loss on Extinguishment of Debt. A loss on extinguishment of debt was recorded in connection with ETP's tender offers in whihc it repurchased approximately $750 million in aggregate principal amount of Senior Notes in January 2012.

Gains on Non-Hedged Interest Rate Derivatives. The three months ended March 31, 2012 reflected gains on non-hedged interest rate swaps for which ETP had total notional amounts outstanding of $1.4 billion as of March 31, 2012, including $800 million of forward-starting floating-to-fixed swaps used to hedge interest rates and $600 million of fixed-to-floating swaps used to swap a portion of ETP's fixed rate debt to floating. During the first quarter of 2012, forward rates increased which resulted in unrealized non-cash gains on our forward-starting floating-to-fixed swaps.

Income Tax Expense. The increase in income tax expense between the periods was primarily due to $7.4 million of deferred income taxes incurred as a result of the gain on deconsolidation of ETP's Propane Business, which was partially offset by a decrease in taxable income within ETP's subsidiaries that are taxable corporations.

Investment in Regency



	Three Months Ended March 31,
	2012			2011			Change
Revenues	$	357,899		$	317,252		$	40,647
Cost of products sold	239,653			216,261			23,392
Gross margin	118,246			100,991			17,255
Operating expenses	40,981			33,672			7,309
Depreciation and amortization	51,506			40,236			11,270
Selling, general and administrative	15,695			18,997			(3,302		)
Losses on disposal of assets	36			28			8
Operating income	10,028			8,058			1,970
Interest expense, net of interest capitalized	(29,557		)	(20,007		)	(9,550		)
Equity in earnings of affiliates	31,958			23,808			8,150
Other, net	16,522			2,414			14,108
Income tax (expense) benefit	(51		)	32			(83		)
Net income	$	28,900		$	14,305		$	14,595

Gross Margin. Regency’s gross margin increased $17.3 million, primarily due to a $17.5 million increase in its gathering and processing operations from increased volumes in South and West Texas.

Operating Expenses. Regency's operating expenses increased primarily due to $3.2 million in increased compressor maintenance

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costs related to material costs, $1.8 million in increased employee expenses and $1.3 million in increased plant operating expenses as a result of increased volumes in South and West Texas.

Depreciation and Amortization. Regency's depreciation and amortization increased $4.4 million from additional assets placed in service in addition to $6.9 million to adjust useful lives in its contract compression operations.

Selling, General and Administrative. Regency's selling, general and administrative costs decreased $3.3 million primarily as a result of costs savings associated with its shared services agreement with ETE and ETP for employee related costs, office rent expense and legal fees.

Interest Expense. Regency's interest expense increased primarily due to additional interest expense associated with the issuance of its $500 million aggregate principal 2021 Senior Notes issued in May 2011.

Equity in Earnings of Affiliates. Regency's equity in earnings increased $11.4 million as a result of its acquisition of a 30% interest in Lone Star in May 2011 which was offset by a $3.8 million decrease in equity in earnings from HPC.

Other, net. Regency's other income increased $14.1 million primarily as a result of a $15.6 million one-time producer payment received in March 2012 for the assignment of certain contracts.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The Parent Company’s principal sources of cash flow have historically derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. Effective with the acquisition of Southern Union, the Parent Company also generates cash flows through Southern Union's wholly-owned subsidiary. 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 the Citrus Merger, we have relinquished approximately $220 million of IDRs to be received from ETP over 16 consecutive quarters, approximately $13.8 million per quarter.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. 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 issued a $2.0 billion Senior Secured Term Loan as permanent financing to fund the cash portion of the Southern Union Merger and pay related fees and expenses, including existing borrowings under our revolving credit facility and for general partnership purposes. We also used a portion of the cash received from ETP in the Citrus Merger (discussed below) to fund the remaining cash portion of the Southern Union Merger.

We expect ETP, Regency and Southern Union to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

ETP

ETP’s ability to satisfy its obligations and pay distributions to its Unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of ETP’s management.

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ETP currently believes that its business has the following future capital requirements, which do not include amounts for ETP's recently announced merger agreement to acquire Sunoco:


•	growth capital expenditures for its midstream and intrastate transportation and storage operations, primarily for construction of new pipelines and compression facilities, for which ETP expects to spend between $700 million and $800 million for the remainder of 2012;


•	growth capital expenditures for its NGL transportation and services operations of between $1.1 billion and $1.2 billion for the remainder of 2012, for which ETP expects to receive capital contributions from Regency related to their 30% interest in Lone Star of between $300 million and $350 million; and

•

maintenance capital expenditures of between $90 million and $100 million for the remainder of 2012, which include (i) capital expenditures for its intrastate operations for pipeline integrity and for connecting additional wells to its intrastate natural gas systems in order to maintain or increase throughput on existing assets; (ii) capital expenditures for its interstate operations, primarily for pipeline integrity; and (iii) capital expenditures related to NGL transportation and services, which includes amounts ETP expects to be funded by Regency related to its 30% interest in Lone Star.

ETP does not expect to make any growth capital expenditures in 2012 related to its interstate transportation operations.

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 it 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 includes 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 its revolving credit facility, the issuance of long-term debt or common units or a combination thereof.

Based on current estimates, ETP expects to utilize capacity under its revolving credit facility, along with cash from ETP’s operations, to fund its announced growth capital expenditures and working capital needs through the end of 2012; 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;


•	borrowings under the Regency Credit Facility;


•	distributions received from unconsolidated affiliates;


•	debt offerings; and


•	issuance of additional partnership units.

Regency expects its growth capital expenditures to be between approximately $775 million and $825 million during 2012, which includes $275 million for its gathering and processing operations, $70 million for its contract compression operations, $40 million for its contract treating operations, between $385 million and $435 million for its joint ventures (which includes between $350 million and $400 million of contributions to Lone Star) and $5 million for its corporate and other operations. In addition, Regency expects its maintenance capital expenditures to be approximately $30 million during 2012.

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.

Southern Union

Cash generated from internal operations constitutes Southern Union's primary source of liquidity. Additional sources of liquidity for working capital purposes include the use of available credit facilities and may include various capital markets and bank debt financings and proceeds from asset dispositions. The availability and terms relating to such liquidity will depend upon various factors and conditions such as Southern Union's combined cash flow and earnings, its resulting capital structure and conditions in the financial markets at the time of such offerings.

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As of March 31, 2012, Southern Union expects its growth capital expenditures to be between approximately $200 million and $250 million for the remainder of 2012 primarily for its gathering and processing operations. In addition, Southern Union expects its maintenance capital expenditures to be between $180 million and $200 million for the remainder of 2012.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for our operating entities products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of acquisitions and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation and amortization expense and non-cash compensation expense. The increase in depreciation and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense result 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 natural gas and propane inventories, and the timing of advances and deposits received from customers.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Cash provided by operating activities during 2012 was $79.4 million as compared to $358.1 million for 2011. Net income was $961.3 million and $199.1 million for 2012 and 2011, respectively. The difference between net income and the net cash provided by operating activities primarily consisted of non-cash items totaling $713.7 million and $175.1 million and changes in operating assets and liabilities of $150.1 million and $37.7 million for 2012 and 2011, respectively.

The non-cash activity in 2012 consisted primarily of the gain on deconsolidation of Propane Business of $1.06 billion and the loss on extinguishment of debt of $115.0 million which were not reflected in 2011. In addition, depreciation and amortization was $161.2 million and $139.3 million for 2012 and 2011, respectively, bridge loan related fees were $62.2 million for 2012 and amortization of finance costs charged to interest were $5.4 million and $5.1 million for 2012 and 2011, respectively.

Cash paid for interest, net of interest capitalized, was $168.0 million and $138.0 million for the three months ended March 31, 2012 and 2011, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, cash contributions to 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, 2012 Compared to Three Months Ended March 31, 2011. Cash used in investing activities during 2012 was $2.16 billion as compared to $290.3 million for 2011. In 2012, we paid cash for acquisitions of $2.98 billion, which primarily consisted of our acquisition of Southern Union for $2.97 billion. In 2011, we paid cash for acquisitions of $3.1 million. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2012 were $594.5 million, including changes in accruals of $52.5 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2011 of $279.6 million, including changes in accruals of $2.5 million.

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.

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Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Cash provided by financing activities during 2012 was $2.24 billion as compared to cash used in financing activities of $11.1 million for 2011. In 2012, ETP received $87.3 million in net proceeds from offerings of ETP Common Units, including $76.7 million under ETP’s equity distribution program (see Note 12 to our consolidated financial statements), as compared to $57.4 million in 2011. In 2012, Regency also received $297.3 million in net proceeds from its offering of Regency Common Units in March 2012. During 2012, we had a consolidated net increase in our debt level of $2.31 billion as compared to a net increase of $233.5 million for 2011, primarily due to our issuance of a $2.0 billion Senior Secured Term Loan which were partially offset by repayments of debt of $2.47 billion. We paid distributions of $139.8 million and $120.8 million to our partners in 2012 and in 2011, respectively. In addition, during 2012 and 2011, ETP paid distributions of $159.2 million and $130.1 million, respectively, on limited partner interests other than those held by the Parent Company. During 2012 and 2011, Regency paid distributions of $60.8 million and $49.6 million, respectively, on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interest on our consolidated statements of cash flows.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	March 31, 2012		December 31, 2011
Parent Company Indebtedness:
ETE Senior Notes	$	1,800,000	$	1,800,000
ETE Senior Secured Term Loan	2,000,000		—
ETE Senior Secured Revolving Credit Facility	—		71,500
Subsidiary Indebtedness:
ETP Senior Notes	7,800,000		6,550,000
Regency Senior Notes	1,350,000		1,350,000
Southern Union Senior Notes	1,286,868		—
Panhandle Senior Notes	1,621,305		—
Transwestern Senior Unsecured Notes	870,000		870,000
HOLP Senior Secured Notes	—		71,314
ETP Revolving Credit Facility	190,000		314,438
Regency Revolving Credit Facility	250,000		332,000
Southern Union Revolving Credit Facility	165,000		—
Other long-term debt	704		10,434
Unamortized discounts, net	156,201		(10,309		)
Fair value adjustments related to interest rate swaps	10,244		11,647
Total debt	17,500,322		11,371,024
Less: current maturities	109,127		424,160
Long-term debt, less current maturities	$	17,391,195	$	10,946,864

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, 2011, filed with the SEC on February 22, 2012 and in Note 10 to our consolidated financial statements. As a result of the Southern Union Merger, we incurred additional indebtedness which is summarized below.

ETE Senior Secured Term Loan

Borrowings bear interest, at either the Eurodollar rate plus an applicable margin or the alternative base rate plus an applicable margin. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are 3.0% for Eurodollar loans and from 2.0% for base rate loans. The effective interest rate on the amount outstanding as of March 31, 2012 was 3.75%.

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Southern Union Junior Subordinated Notes

Panhandle Term Loans

Bridge Term Loan Facility

ETP Senior Notes

In January 2012, ETP completed a public offering of $1 billion aggregate principal amount of 5.20% Senior Notes due February 1, 2022 and $1 billion aggregate principal amount of 6.50% Senior Notes due February 1, 2042. ETP used the net proceeds of $1.98 billion from the offering to fund the cash portion of the purchase price of the Citrus Merger and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.

In January 2012, ETP completed a cash tender offer for approximately $750 million aggregate principal amount of specified series of the ETP Senior Notes. The tender offer consisted of two separate offers: an Any and All Offer and a Maximum Tender Offer. The senior notes described below were repurchased under the Any and All Offer and Maximum Tender Offer for a total cost of $885.9 million and a loss on extinguishment of $115.0 million was recorded during the three months ended March 31, 2012.

In the Any and All Offer, ETP offered to purchase, under certain conditions, any and all of its 5.65% Senior Notes due August 1, 2012, at a fixed price. Pursuant to the Any and All Offer, ETP purchased $292 million in aggregate principal amount on January 19, 2012.

In the Maximum Tender Offer, ETP offered to purchase, under certain conditions, certain series of outstanding ETP Senior Notes at a fixed spread over the index rate. Pursuant to this tender offer, on February 7, 2012, ETP purchased $200 million aggregate principal amount of its 9.7% Senior Notes due March 15, 2019, $200 million aggregate principal amount of its 9.0% Senior Notes due April 15, 2019 and $58.1 million aggregate principal amount of its 8.5% Senior Notes due April 15, 2014.

Revolving Credit Facilities

Parent Company Credit Facility. As of March 31, 2012, we had no outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $200 million.

ETP Credit Facility. As of March 31, 2012, ETP had a balance of $190.0 million outstanding under the ETP Credit Facility, and the amount available under the ETP Credit Facility was $2.28 billion, after taking into account letters of credit of $28.3 million. The weighted average interest rate on the total amount outstanding at March 31, 2012 was 1.74%.

Regency Credit Facility. As of March 31, 2012, Regency had a balance of $250.0 million outstanding under the Regency Credit and the amount available under the Regency Credit Facility was $638.5 million, taking into account letters of credit of $11.5 million. The weighted average interest rate on the total amount outstanding as of March 31, 2012 was 3.09%.

Southern Union Credit Facilities. The Southern Union Credit Facility provides for a $700 million revolving credit facility which matures on May 20, 2016. Borrowings on the Southern Union Credit Facility are available for working capital, other general company purposes and letter of credit requirements. The interest rate and commitment fee under the Southern Union Credit Facility are calculated using a pricing grid, which is based on the credit ratings for Southern Union's senior unsecured notes. The annualized interest rate for the Southern Union Credit Facility was 1.86% as of March 31, 2012.

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Covenants Related to Our Credit Agreements

Covenants Related to Southern Union


•	Under the Southern Union Credit Facility, the consolidated debt to total capitalization ratio, as defined therein, cannot exceed 65%;


•	Under the Southern Union Credit Facility, Southern Union must maintain an earnings before interest, tax, depreciation and amortization interest coverage ratio of at least 2.00 times;


•	Under Southern Union’s First Mortgage Bond indentures for the Fall River Gas division of New England Gas Company, Southern Union’s consolidated debt to total capitalization ratio, as defined therein, cannot exceed 70% at the end of any calendar quarter; and


•	All of Southern Union’s major borrowing agreements contain cross-defaults if Southern Union defaults on an agreement involving at least $10 million of principal.

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, 2012.

Contingent Residual Support Agreement — AmeriGas

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 Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the Senior Notes.

In connection with the Propane Contribution, ETP entered into and delivered a Contingent Residual Support Agreement 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 Contingent Residual Support Agreement.

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Contractual Obligations

The following table summarizes our long-term debt and other contractual obligations as of March 31, 2012 (in thousands):



	Payments Due by Period
Contractual Obligations	Total		Remainder of 2012		2013-2014		2015-2016		Thereafter
Long-term debt	$	17,333,878	$	108,887	$	1,231,775	$	1,936,710	$	14,056,506
Interest on long-term debt ^(a)	9,886,042		750,104		1,795,734		1,600,449		5,739,755
Payments on derivatives	92,129		4,037		87,501		—		591
Purchase commitments ^(b)	986,794		298,055		243,321		176,366		269,052
Lease obligations	371,751		26,491		71,182		62,478		211,600
Distributions and redemption of preferred units ^(c)	291,424		23,836		49,097		15,563		202,928
Other	29,130		22,108		1,503		971		4,548
Totals^(d)	$	28,991,148	$	1,233,518	$	3,480,113	$	3,792,537	$	20,484,980

^(a)

Interest payments on long-term debt are based on the principal amount of debt obligations as of March 31, 2012. With respect to variable rate debt, the interest payments were estimated using the interest rate as of March 31, 2012. To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.

^(b)

We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the March 31, 2012 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.


^(c)	Assumes the Preferred Units are converted to ETE Common Units on May 26, 2014 and assumes the Regency Preferred Units are redeemed for cash on September 2, 2029.


^(d)	Excludes net non-current deferred tax liabilities of $2.01 billion due to uncertainty of the timing of future cash flows for such liabilities.

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, 2011:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2011	February 7, 2012	February 17, 2012	$	0.625
March 31, 2012	May 4, 2012	May 18, 2012	0.625

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The total amounts of distributions declared and/or paid during the three months ended March 31, 2012 and 2011 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,
	2012		2011
Limited Partners	$	174,972	$	124,848
General Partner interest	433		388
Total Parent Company distributions	$	175,405	$	125,236

Cash Distributions Received from Subsidiaries

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,
	2012		2011
Distributions from ETP:
Limited Partners ⁽²⁾	$	46,900	$	44,890
General Partner interest	4,914		4,896
IDRs ⁽¹⁾	99,548		103,182
Total distributions from ETP	151,362		152,968
Distributions from Regency:
Limited Partners	12,083		11,689
General Partner interest	1,324		1,269
IDRs	2,074		1,114
Total distributions from Regency	15,481		14,072
Total distributions received from subsidiaries	$	166,843	$	167,040


⁽¹⁾	In connection with the Citrus Merger, we relinquished approximately $220 million of IDRs to be received from ETP over 16 consecutive quarters, approximately $13.8 million per quarter.


⁽²⁾	Includes approximately $2.0 million of common unit distributions paid to Southern Union for the quarter ended March 31, 2012 in respect of approximately 2,249,092 ETP Common Units issued to Southern Union in connection with the Citrus Merger.

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, 2011:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2011	February 7, 2012	February 14, 2012	$	0.89375
March 31, 2012	May 4, 2012	May 15, 2012	0.89375

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The total amounts of ETP distributions declared and/or paid during the three months ended March 31, 2012 and 2011 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,
	2012		2011
Limited Partners:
Common Units	$	205,172	$	186,321
Class E Units	3,121		3,121
General Partner interest	4,914		4,896
IDRs	99,548		103,182
Total ETP distributions	$	312,755	$	297,520

Cash Distributions Paid by Regency

Following are distributions declared and/or paid by Regency subsequent to December 31, 2011:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2011	February 6, 2012	February 13, 2012	$	0.46
March 31, 2012	May 7, 2012	May 14, 2012	0.46

The total amounts of Regency distributions declared and/or paid during the three months ended March 31, 2012 and 2011 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,
	2012		2011
Limited Partners	$	78,248	$	64,895
General Partner interest	1,324		1,269
IDRs	2,074		1,114
Total Regency distributions	$	81,646	$	67,278

CRITICAL ACCOUNTING POLICIES

As a result of the Southern Union Merger on March 26, 2012, the following significant accounting policy has been added to our critical accounting policies described in our Form 10-K for the year ended December 31, 2011.

Pensions and Other Postretirement Benefit Plans

The Partnership is required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. The Partnership recognizes the changes in the funded status of its defined benefit postretirement plans through AOCI.

The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.

The discount rate is established by using the Citigroup Pension Discount Curve as published on the Society of Actuaries website as the hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced.

The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2011, 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, 2011, other than additional primary market risk exposures related to the Southern Union Merger. Other than changes due to the Southern Union Merger, there have been no material changes to our primary market risk exposures or how those exposures are managed since December 31, 2011.

The United States Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173) in 2010, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. This legislation requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. The CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. It is not possible at this time to predict when the CFTC will make these regulations effective. The legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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, 2012 and December 31, 2011.

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 portfolios may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

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

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ETP

Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power and gallons for propane. Dollar amounts are presented in thousands.



	March 31, 2012							December 31, 2011
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX⁽¹⁾	11,280,000		$	(25,050	)	$	1,066	(151,260,000	)	$	(22,582	)	$	2,593
Power:
Forwards	(1,000	)	410			33		—		—			—
Options — Calls	84		107			9		—		—			—
Options — Puts	32		44			4		—		—			—
(Non-Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX	(43,882,500	)	(793		)	56		(61,420,000	)	4,024			266
Swing Swaps IFERC	(62,117,500	)	(1,553		)	589		92,370,000		(1,072		)	138
Fixed Swaps/Futures	(2,042,500	)	3,029			2,493		797,500		(4,301		)	145
Forward Physical Contracts (MMbtu)	(43,604,214	)	2,449			2,323		(10,672,028	)	(13		)	1,118
Propane:
Forwards/Swaps	6,571,500		(879		)	828		38,766,000		(4,122		)	5,290
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX	(25,920,000	)	95			190		(28,752,500	)	(808		)	181
Fixed Swaps/Futures	(55,690,000	)	33,987			14,959		(45,822,500	)	70,761			14,048
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas:
Basis Swaps IFERC/NYMEX	(17,400,000	)	100			115		—		—			—
Fixed Swaps/Futures	(35,650,000	)	16,672			11,033		—		—			—
Options — Puts	2,700,000		6,765			597		3,600,000		6,435			933
Options — Calls	(2,700,000	)	(2		)	3		(3,600,000	)	(12		)	13

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

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Regency

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



	March 31, 2012						December 31, 2011
	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
Natural Gas:
Fixed Swaps/Futures	2,838,000	$	4,677		$	821	—	$	—		$	—
Propane:
Forwards/Swaps	10,584,000	(658		)	1,335		—	—			—
NGLs:
Forwards/Swaps	435,000	(2,757		)	2,787		—	—			—
Options — Puts	110,000	880			185		110,000	309			113
WTI Crude Oil:
Forwards/Swaps	401,000	(2,134		)	4,144		—	—			—
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures	—	—			—		2,198,000	$	3,907		$	717
Propane:
Forwards/Swaps	—	—			—		11,802,000	(2,488		)	1,588
NGLs:
Forwards/Swaps	—	—			—		533,000	(5,979		)	2,956
WTI Crude Oil:
Forwards/Swaps	—	—			—		350,000	(1,029		)	3,429

Regency, for accounting purposes, de-designated its swap contracts on January 1, 2012 and is accounting for these contracts using mark-to-market accounting.

Southern Union

The following table summarizes SUGS' principal derivative instruments as of March 31, 2012 (all instruments are settled monthly), which were developed based upon historical and projected operating conditions and processable volumes. Notional volumes are presented in MMBtu for natural gas and barrels for NGLs.



	March 31, 2012
	Notional Volume	Fair Value Asset (Liability)			Effect of Hypothetical Change ⁽¹⁾
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas:
Fixed Swaps/Futures	2,750,000	$	6,635		$	10,405
Natural Gas Liquids:
Fixed Swaps/Futures	1,170,675	(311		)	1,304


⁽¹⁾	Excludes the effects of hedging, assumes normal operating conditions and estimates the effect of a change in price of $0.01 per gallon of NGL and $1.00 per MMBtu of natural gas.

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Interest Rate Risk

As of March 31, 2012, we and our subsidiaries had $3.66 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $36.6 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, 2012 and December 31, 2011 (dollars in thousands), none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

March 31, 2012

December 31, 2011

ETE

March 2017

Pay a fixed rate of 1.27% and receive a floating rate

375,000

—

ETP

May 2012 ⁽²⁾

Forward starting to pay a fixed rate of 2.59% and receive a floating rate

—

350,000

ETP

August 2012⁽²⁾

Forward starting to pay a fixed rate of 3.51% and receive a floating rate

—

500,000

ETP

July 2013 ⁽²⁾

Forward starting to pay a fixed rate of 4.02% and receive a floating rate

400,000

300,000

ETP

July 2014 ⁽²⁾

Forward starting to pay a fixed rate of 4.26% and receive a floating rate

400,000

—

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

600,000

500,000

Regency

April 2012

Pay a fixed rate of 1.325% and receive a floating rate

250,000

Southern Union

November 2021

Pay a fixed rate of 3.746% and receive a floating rate

450,000

N/A

Southern Union

November 2016

Pay a fixed rate of 2.913% and receive a floating rate

75,000

N/A


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


⁽²⁾	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 non-hedged interest rate derivatives) of approximately $60.8 million as of March 31, 2012 and $83.3 million as of December 31, 2011. For ETP’s $600 million of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow (swap settlements) of $6 million annually. For ETP’s forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

Credit Risk

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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, 2012 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

We closed the Southern Union Merger on March 26, 2012 and have begun the evaluation of the internal control structure of Southern Union. We expect that evaluation to continue during the remainder of 2012. In recording the Southern Union Merger, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of Southern Union from the date of acquisition that are included in our results of operations for the three months ended March 31, 2012.

None of the changes resulting from the Southern Union Merger were in response to any identified deficiency or weakness in our internal control over financial reporting. Other than changes resulting from the Southern Union Merger, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended March 31, 2012 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, 2011 and Note 16 — Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

ITEM 1A. RISK FACTORS

ETP's recently announced entry into a definitive merger agreement whereby ETP will acquire Sunoco Inc. ("Sunoco Merger") presents several risks. Some risks are similar to the risks associated with our existing business that have recently been disclosed. However, certain of those risks represent new risks related to our business or existing risks that have become more significant. The following risk factors should be read in conjunction with our risk factors described in “Part I — Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011.

The recently announced Sunoco Merger is subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to unitholders.

The recently announced Sunoco Merger involves potential risks, including, among other things:

• the validity of our assumptions about revenues, capital expenditures and operating costs of the acquired business or assets, as well as assumptions about achieving synergies with our existing businesses;

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• an increase in our interest expense and financial leverage resulting from any additional debt incurred to finance the acquisition consideration, which could offset the expected accretion to our unitholders from such acquisition and could be exacerbated by volatility in the credit or debt capital markets;

• a failure to realize anticipated benefits, such as increased distributable cash flow per unit, enhanced competitive position or new customer relationships;

• a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;

• difficulties operating in new geographic areas and new lines of business;

• the incurrence or assumption of unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

• the inability to hire, train or retrain qualified personnel to manage and operate our growing business and assets, including any newly acquired business or assets;

• the diversion of management's attention from our existing businesses; and

• the incurrence of significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

Our reviews of businesses or assets proposed to be acquired are inherently incomplete because it generally is not feasible to perform an in-depth review of businesses and assets involved in each acquisition given time constraints imposed by sellers. Even a detailed review of assets and businesses may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the assets or businesses to fully assess their deficiencies and potential. Inspections may not always be performed on every asset, and environmental problems are not necessarily observable even when an inspection is undertaken.

The completion of the Sunoco Merger will require ETP to obtain debt or equity financing, or a combination thereof, which may not be available to it on acceptable terms, or at all.

The Sunoco Merger requires that ETP pay approximately $2.65 billion to Sunoco shareholders as cash consideration upon the consummation of the merger which is expected to close in the third or forth quarter of 2012. ETP plans to fund a significant portion of this cash consideration with cash that it expects Sunoco to have on hand at th time of the consummation of the Sunoco Merger. ETP expects to fund the remaining portion of the cash consideration initially with borrowings under its revolving credit facility, the issuance of debt securities in the public or private markets, the issuance of common units, or a combination thereof. As of March 31, 2012, Sunoco had cash on hand of $2.06 billion; however, Sunoco may have substantially less cash on hand at that the time of the consummation of the Sunoco Merger due to unforeseen circumstances related to its business and operations. The merger agreement between Sunoco and ETP related to the Sunoco Merger does not require Sunoco to have any specified minimum level of cash on hand at the time of the consummation of the Sunoco Merger and, as a result, in the event that Sunoco has less cash on hand than ETP currently expects it will have at such time, ETP will be required to raise more cash through borrowings under ETP's revolving credit facility, the issuance of debt securities or the issuance of common units. The incurrence of this additional indebtedness may increase ETP's overall level of debt and may adversely affect its ratios of total indebtedness to EBITDA and EBITDA to interest expense. ETP cannot be certain that it will be able to issue its debt or equity securities on terms satisfactory to it, or at all. If ETP is unable to finance the cash portion of the consideration for the Sunoco Merger with borrowings under its revolving credit facility or through the issuance of debt securities in the public or private markets, ETP could be required to seek alternative financing, the terms of which may not be attractive to ETP, or ETP may be unable to fulfill its obligations under the Sunoco Merger.

The failure to successfully combine the businesses of ETP and Sunoco in the expected time frame may adversely affect ETP's future results.

The success of the Sunoco Merger will depend, in part, on the ability of ETP to realize the anticipated benefits from combining the businesses of ETP and Sunoco. To realize these anticipated benefits, ETP's and Sunoco's businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the Sunoco Merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the Sunoco Merger.

ETP and Sunoco, including their respective subsidiaries, have operated and, until the completion of the Sunoco Merger, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each company's ongoing businesses or inconsistencies in their standards, controls, procedures and policies. Any or all of those occurrences could adversely affect ETP's ability to maintain relationships with customers and employees after the

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Sunoco Merger or to achieve the anticipated benefits of the Sunoco Merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on each of ETP and Sunoco.

The completion of the Sunoco Merger is subject to the satisfaction of certain conditions to closing, and the date that the Sunoco Merger would be consummated is uncertain.

The completion of the Sunoco Merger is subject to the approval of the Sunoco stockholders, the absence of a material adverse change to the business or results of operation of ETP and Sunoco, the receipt of necessary regulatory approvals and the satisfaction or waiver of other conditions specified in the merger agreement related to the Sunoco transaction. Another party may express public interest in completing a transaction with Sunoco similar to the Sunoco Merger and may be prepared to pay consideration to the stockholders of Sunoco in an amount greater than ETP is willing to pay, which could delay or prevent the stockholders of Sunoco from approving the Sunoco Merger. In the event those conditions to closing are not satisfied or waived, we would not complete the Sunoco Merger.

While we expect to complete the Sunoco Merger in the second half of 2012, the completion date of the Sunoco Merger might be later than expected due to delays in obtaining required regulatory approvals or other unforeseen events.

The pendency of the Sunoco Merger could materially adversely affect the future business and operations of ETP or Sunoco or result in a loss of Sunoco employees.

In connection with the pending Sunoco Merger, it is possible that some customers, suppliers and other persons with whom ETP, ETP's subsidiaries or Sunoco have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with Sunoco as a result of the Sunoco Merger, which could negatively impact revenues, earnings and cash flows of ETP or Sunoco, as well as the market prices of ETP common units or shares of Sunoco common stock, regardless of whether the Sunoco Merger is completed. Similarly, current and prospective employees of Sunoco may experience uncertainty about their future roles with ETP and Sunoco following completion of the Sunoco Merger, which may materially adversely affect the ability of ETP and Sunoco to attract and retain key employees.

Failure to complete the Sunoco Merger could negatively impact the unit price of ETP and its respective future businesses and financial results.

If the Sunoco Merger is not completed, the ongoing business of ETP may be adversely affected and ETP will be subject to several risks and consequences, including the following:


•	ETP will be required to pay certain costs relating to the Sunoco Merger, whether or not the Sunoco Merger is completed, such as legal, accounting, financial advisor and printing fees;


•	ETP would not realize the expected benefits of the Sunoco Merger;


•	under the merger agreement, ETP is subject to certain restrictions on the conduct of its business prior to completing the Sunoco Merger which may adversely affect its ability to execute certain of its business strategies; and


•	matters relating to the Sunoco Merger may require substantial commitments of time and resources by ETP management, which could otherwise have been devoted to other opportunities that may have been beneficial to ETP.

In addition, if the Sunoco Merger is not completed, ETP may experience negative reactions from the financial markets and from their respective customers and employees. ETP also could be subject to litigation related to any failure to complete the Sunoco Merger or to enforcement proceedings commenced against ETP to attempt to force it to perform its obligations under the merger agreement.

Pending litigation against ETP and Sunoco could result in an injunction preventing completion of the Sunoco Merger, the payment of damages in the event the Sunoco Merger is completed and/or may adversely affect the combined company's business, financial condition or results of operations following the Sunoco Merger.

In connection with the Sunoco Merger, purported stockholders of Sunoco have filed several stockholder class action lawsuits against ETP, Sunoco, and the Sunoco Board. Among other remedies, the plaintiffs seek monetary damages and to enjoin the Sunoco Merger. If a final settlement is not reached, or if a dismissal is not obtained, these lawsuits could prevent or delay completion of the Sunoco Merger and result in substantial costs to ETP and Sunoco, including any costs associated with the indemnification of directors. Additional lawsuits may be filed against ETP and/or Sunoco related to the Sunoco Merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Sunoco Merger is completed may adversely affect the combined company's business, financial condition or results of operations.

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If the merger agreement is terminated, Sunoco may be obligated to reimburse ETP for costs incurred related to the Sunoco Merger and, under certain circumstances, pay a breakup fee to ETP. Sunoco may be unable to reimburse these costs or pay any potential breakup fee to ETP.

In certain circumstances, upon termination of the merger agreement, Sunoco would be responsible for reimbursing ETP for up to $20 million in expenses related to the transaction and may be obligated to pay a breakup fee to ETP of $225 million. If the merger agreement is terminated, the expense reimbursements and the breakup fee required to be paid by Sunoco under the merger agreement may require Sunoco to seek loans or borrow amounts to enable it to pay these amounts to ETP. In either case, Sunoco may not be able to fulfill such obligations.

Sunoco will be a corporate subsidiary of ETP after the Sunoco Merger and will remain subject to corporate-level income taxes.

After the Sunoco Merger, ETP will own and operate certain aspects of Sunoco's business through Sunoco as a wholly owned corporate subsidiary of ETP. Accordingly, Sunoco will continue to be subject to corporate-level tax, which may reduce the cash available for distribution to ETP and, in turn, to ETP unitholders. If the IRS were to successfully assert that Sunoco has more tax liability than ETP anticipated or legislation were enacted that increased the corporate tax rate, the cash available for distribution by ETP could be further reduced.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

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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
2.1	1-32740 (8-K) (3/28/12)	2.1	Amendment No. 2, dated as of March 23, 2012, to Amended and Restated Agreement and Plan of Merger, by and among Energy Transfer Equity, L.P., Energy Transfer Partners, L.P., Citrus ETP Acquisition, L.L.C, Southern Union Company and CrossCountry Energy, LLC, dated as of July 19, 2011.
3.1	1-32740 (8-K) (3/28/12)	3.1	Amendment No. 1, dated March 26, 2012, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated July 28, 2009.
3.2	1-32740 (8-K) (3/28/12)	3.2	Amendment No. 2, dated March 26, 2012, to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P., dated April 17, 2007.
3.3	1-32740 (8-K) (3/28/12)	3.3	Amendment No. 1, dated March 26, 2012, to the Fourth Amended and Restated Agreement of Limited Liability Company Agreement of Energy Transfer Partners, L.L.C., dated August 10, 2010.
4.1	1-32740 (8-K) (2/16/12)	4.1	Second Supplemental Indenture dated as of February 16, 2012, between Energy Transfer Equity, L.P., and U.S. Bank National Association.
10.1	1-32740 (8-K) (3/28/12)	10.1	Guarantee of Collection, made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. under the Indenture dated as of January 18, 2005, as supplemented by the Tenth Supplemental Indenture dated as of January 17, 2012.
10.2	1-32740 (8-K) (3/28/12)	10.2	Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P. and Citrus ETP Finance LLC.
10.3	1-32740 (8-K) (3/28/12)	10.3	Senior Secured Term Loan Agreement dated March 23, 2012, by and among Energy Transfer Equity, L.P. and Credit Suisse AG, as Administrative Agent, and the other lenders from time to time party thereto.
10.4	1-32740 (8-K) (3/28/12)	10.4	Amendment No. 2 to Credit Agreement dated, as of March 23, 2012, by and among Energy Transfer Equity, L.P. and Credit Suisse AG, as Administrative Agent and the other lenders party thereto.
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, 2012 and December 31, 2011; (ii) our Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011; (iii) our Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011; (iv) our Consolidated Statement of Equity for the three months ended March 31, 2012; (v) our Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011; and (vi) the notes to our Consolidated Financial Statements.

_________________

* Incorporated herein by reference.

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SIGNATURE

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



		ENERGY TRANSFER EQUITY, L.P.

		By:	LE GP, L.L.C., its General Partner

Date:	May 9, 2012	By:	/s/ John W. McReynolds
			John W. McReynolds
			President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)