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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2011

¨	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 x 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 x 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.

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

At August 2, 2011, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P. 222,972,708 Common Units

FORM 10-Q

INDEX

Energy Transfer Equity, L.P. and Subsidiaries


PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets – June 30, 2011 and December 31, 2010			1

Consolidated Statements of Operations – Three and Six Months Ended June 30, 2011 and 2010			3

Consolidated Statements of Comprehensive Income (Loss) – Three and Six Months Ended June 30, 2011 and 2010			4

Consolidated Statement of Equity – Six Months Ended June 30, 2011			5

Consolidated Statements of Cash Flows – Six Months Ended June 30, 2011 and 2010			6

Notes to Consolidated Financial Statements			7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			38

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			52

ITEM 4. CONTROLS AND PROCEDURES			55

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS			55

ITEM 1A. RISK FACTORS			56

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			58

ITEM 3. DEFAULTS UPON SENIOR SECURITIES			58

ITEM 4. [RESERVED]

ITEM 5. OTHER INFORMATION			58

ITEM 6. EXHIBITS			58

SIGNATURE			62

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,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “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, projected, forecasted, estimated or expressed 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” 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, 2010 filed with the Securities and Exchange Commission (“SEC”) on February 28, 2011.

Definitions

The following is a list of certain acronyms and terms generally used throughout this document:


/d		per day

Bbls		barrels

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

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

Mcf		thousand cubic feet

MMBtu		million British thermal units

MMcf		million cubic feet

Bcf		billion cubic feet

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

Tcf		trillion cubic feet

LIBOR		London Interbank Offered Rate

NYMEX		New York Mercantile Exchange

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 and is separate from other reservoirs

WTI		West Texas Intermediate Crude

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)


	June 30, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	148,471		$	86,264
Marketable securities		1,996			2,032
Accounts receivable, net of allowance for doubtful accounts of $6,908 and $6,706 as of June 30, 2011 and December 31, 2010, respectively		642,928			612,357
Accounts receivable from related companies		82,510			76,331
Inventories		348,177			366,384
Exchanges receivable		19,451			21,926
Price risk management assets		13,104			16,357
Other current assets		142,334			109,359

Total current assets		1,398,971			1,291,010

PROPERTY, PLANT AND EQUIPMENT		15,461,476			13,284,430
ACCUMULATED DEPRECIATION		(1,687,004	)		(1,431,698	)

		13,774,472			11,852,732

ADVANCES TO AND INVESTMENTS IN AFFILIATES		1,350,627			1,359,979
LONG-TERM PRICE RISK MANAGEMENT ASSETS		7,468			13,971
GOODWILL		2,008,896			1,600,611
INTANGIBLES AND OTHER ASSETS, net		1,325,724			1,260,427

Total assets	$	19,866,158		$	17,378,730

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)


	June 30, 2011			December 31, 2010
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	451,795		$	421,556
Accounts payable to related companies		14,885			27,351
Accrued distributions to ETE partners		139,790			—
Exchanges payable		19,461			16,003
Price risk management liabilities		20,729			13,172
Accrued and other current liabilities		589,762			567,688
Current maturities of long-term debt		22,998			35,305

Total current liabilities		1,259,420			1,081,075

LONG-TERM DEBT, less current maturities		11,123,820			9,346,067
SERIES A CONVERTIBLE PREFERRED UNITS (Note 10)		334,170			317,600
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		60,934			79,465
OTHER NON-CURRENT LIABILITIES		252,892			235,848

COMMITMENTS AND CONTINGENCIES (Note 14)

PREFERRED UNITS OF SUBSIDIARY (Note 10)		71,040			70,943

EQUITY:
General Partner		88			520
Limited Partners:
Common Unitholders		(23,273	)		115,350
Accumulated other comprehensive income (loss)		(356	)		4,798

Total partners’ capital (deficit)		(23,541	)		120,668
Noncontrolling interest		6,787,423			6,127,064

Total equity		6,763,882			6,247,732

Total liabilities and equity	$	19,866,158		$	17,378,730

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
REVENUES:
Natural gas operations	$	1,728,951		$	1,140,768		$	3,157,908		$	2,447,477
Retail propane		220,296			197,147			748,762			730,586
Other		25,659			24,613			57,356			56,446

Total revenues		1,974,906			1,362,528			3,964,026			3,234,509

COSTS AND EXPENSES:
Cost of products sold — natural gas operations		1,122,857			723,835			2,006,626			1,636,441
Cost of products sold — retail propane		134,728			110,282			445,592			415,263
Cost of products sold — other		6,567			6,336			13,360			13,614
Operating expenses		222,717			179,745			443,413			350,493
Depreciation and amortization		148,530			98,035			287,786			184,366
Selling, general and administrative		78,946			65,038			142,445			116,147

Total costs and expenses		1,714,345			1,183,271			3,339,222			2,716,324

OPERATING INCOME		260,561			179,257			624,804			518,185

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(181,517	)		(129,036	)		(349,446	)		(250,707	)
Equity in earnings of affiliates		28,819			12,193			54,260			18,374
(Losses) gains on disposal of assets		(681	)		1,375			(2,435	)		(489	)
Gains (losses) on non-hedged interest rate derivatives		1,883			(22,468	)		3,403			(36,892	)
Impairment of investment in affiliate		—			(52,620	)		—			(52,620	)
Other, net		2,811			(5,213	)		(9,715	)		(3,070	)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		111,876			(16,512	)		320,871			192,781
Income tax expense		5,224			4,053			15,127			9,264

INCOME (LOSS) FROM CONTINUING OPERATIONS		106,652			(20,565	)		305,744			183,517
Income from discontinued operations		—			86			—			86

NET INCOME (LOSS)		106,652			(20,479	)		305,744			183,603

LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST		40,367			(39,747	)		150,819			51,558


NET INCOME ATTRIBUTABLE TO PARTNERS		66,285			19,268			154,925			132,045

GENERAL PARTNER’S INTEREST IN NET INCOME		205			60			479			409


LIMITED PARTNERS’ INTEREST IN NET INCOME	$	66,080		$	19,208		$	154,446		$	131,636


BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.30		$	0.09		$	0.69		$	0.59


BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,972,708			222,941,172			222,963,741			222,941,140


DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.30		$	0.09		$	0.69		$	0.59


DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,972,708			222,941,172			222,963,741			222,941,140

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net income (loss)	$	106,652		$	(20,479	)	$	305,744		$	183,603

Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		123			1,725			(13,416	)		2,555
Change in value of derivative instruments accounted for as cash flow hedges		3,829			(19,303	)		(7,009	)		4,500
Change in value of available-for-sale securities		(643	)		(724	)		(35	)		(3,053	)

		3,309			(18,302	)		(20,460	)		4,002

Comprehensive income (loss)		109,961			(38,781	)		285,284			187,605
Less: Comprehensive income (loss) attributable to noncontrolling interest		43,250			(50,410	)		135,513			57,718

Comprehensive income attributable to partners	$	66,711		$	11,629		$	149,771		$	129,887

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2011

(Dollars in thousands)

(unaudited)


	General Partner			Common Unitholders			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2010	$	520		$	115,350		$	4,798		$	6,127,064		$	6,247,732
Distributions to ETE partners		(1,194	)		(384,612	)		—			—			(385,806	)
Subsidiary distributions		—			—			—			(376,440	)		(376,440	)
Subsidiary units issued for cash		285			91,789			—			882,030			974,104
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings		—			549			—			21,684			22,233
Non-cash executive compensation		—			13			—			612			625
Other, net		(2	)		(808	)		—			(3,040	)		(3,850	)
Other comprehensive loss, net of tax		—			—			(5,154	)		(15,306	)		(20,460	)
Net income		479			154,446			—			150,819			305,744

Balance, June 30, 2011	$	88		$	(23,273	)	$	(356	)	$	6,787,423		$	6,763,882

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)


	Six Months Ended June 30,
	2011			2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:
Net income	$	305,744		$	183,603
Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in affiliate		—			52,620
Proceeds from termination of interest rate derivatives		—			15,395
Depreciation and amortization		287,786			184,366
Amortization of finance costs charged to interest		9,577			6,311
Non-cash unit-based compensation expense		22,460			15,194
Non-cash executive compensation expense		625			625
Losses on disposal of assets		2,435			489
Distributions in excess of equity in earnings of affiliates, net		29,875			12,257
Other non-cash		18,634			(5,241	)
Changes in operating assets and liabilities, net of effects of acquisitions (Note 4)		21,201			336,317

Net cash provided by operating activities		698,337			801,936

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received		(1,948,612	)		(129,390	)
Capital expenditures (excluding allowance for equity funds used during construction)		(794,151	)		(629,372	)
Contributions in aid of construction costs		13,967			7,957
Advances to affiliates, net		(22,668	)		(44,518	)
Proceeds from the sale of assets		6,925			9,138

Net cash used in investing activities		(2,744,539	)		(786,185	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		5,202,535			338,017
Principal payments on debt		(3,420,348	)		(434,250	)
Subsidiary equity offering, net of issue costs		974,104			574,522
Distributions to partners		(246,016	)		(241,523	)
Debt issuance costs		(22,198	)		(5,978	)
Distributions to noncontrolling interests		(376,440	)		(230,605	)
Other		(3,228	)		—

Net cash provided by financing activities		2,108,409			183

INCREASE IN CASH AND CASH EQUIVALENTS		62,207			15,934
CASH AND CASH EQUIVALENTS, beginning of period		86,264			68,315

CASH AND CASH EQUIVALENTS, end of period	$	148,471		$	84,249

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

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:

Energy Transfer Equity, L.P. (together with its subsidiaries, the “Partnership,” “we,” or “ETE”) is a publicly traded Delaware limited partnership that directly and indirectly owns equity interests in Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”), both publicly traded master limited partnerships engaged in strategic diversified energy-related services.

At June 30, 2011, our equity interests consisted of:


	General Partner Interest (as a % of total partnership interest)			Incentive Distribution Rights (“IDRs”)			Common Units
ETP		1.6	%		100	%		50,226,967
Regency		1.9	%		100	%		26,266,791

The unaudited consolidated financial statements of ETE presented herein for the three and six month periods ended June 30, 2011 and 2010 include the results of operations of:

•

the Parent Company;

•

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

•

ETP’s and Regency’s wholly-owned subsidiaries; and

•

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

ETE obtained control of Regency on May 26, 2010, and as such, the three and six month periods ended June 30, 2010 include the results of Regency for the period from the acquisition date through the end of the respective periods.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency, Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

Business Operations

The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements, distributions to its partners and holders of the Series A Convertible Preferred Units (the “Preferred Units”) and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to fully understand the financial condition of the Parent Company on a stand-alone basis, see Note 19 for stand-alone financial information apart from that of the consolidated partnership information included herein.

The following is a brief description of ETP’s and Regency’s operations:

•

ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arkansas, Arizona, Colorado, Louisiana, Mississippi, 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 three storage facilities located in Texas. ETP also holds a 70% interest in a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. ETP is also one of the three largest retail marketers of propane in the United States.

•

Regency is a publicly traded Delaware limited partnership formed in 2005 engaged in the gathering, treating, processing, compressing and transportation of natural gas and NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas production 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 primarily located in 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 a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2010, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership, as of June 30, 2011 and for the three and six month periods ended June 30, 2011 and 2010, have been prepared in accordance with accounting principles generally accepted in the United States of America (“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 June 30, 2011, and the Partnership’s results of operations and cash flows for the three and six months ended June 30, 2011 and 2010. 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, 2010, as filed with the SEC on February 28, 2011.

Certain prior period amounts have been reclassified to conform to the 2011 presentation. These reclassifications had no impact on net income or total equity.

2.	ESTIMATES:

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

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

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in 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.

3.	ACQUISITION:

LDH Acquisition

On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by ETP and 30% by Regency, acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), from Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”) for approximately $1.97 billion in cash (the “LDH Acquisition”). The cash purchase price paid at closing is subject to post-closing adjustments. ETP contributed approximately $1.38 billion to ETP-Regency LLC upon closing to fund its 70% share of the purchase price, while Regency contributed approximately $591.7 million to fund its 30% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star NGL LLC (“Lone Star”).

Lone Star owns and operates a natural gas liquids storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in West Texas, passes through the Barnett Shale production area in North Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana. The acquisition of Lone Star significantly expands the Partnership’s asset portfolio by adding a NGL platform with storage, transportation and fractionation capabilities. This acquisition is expected to provide us with additional consistent fee-based revenues.

ETP accounted for the LDH Acquisition using the acquisition method of accounting. Lone Star’s results of operations are consolidated into our ETP reporting segment, except for Lone Star’s 20% investment in a processing plant, while Lone Star’s results are recorded as an equity method investment in our Regency reporting segment. Regency’s equity method investment in Lone Star is reflected by ETP as noncontrolling interest attributable to Lone Star. These amounts have been eliminated in our consolidated financial statements.

The following summarizes the preliminary assets acquired and liabilities assumed recognized at the acquisition date:


Total current assets	$	118,371
Property, plant and equipment⁽¹⁾		1,438,704
Goodwill		408,285
Intangible assets		83,000
Other assets		157

		2,048,517


Total current liabilities		76,850
Other long-term liabilities		438

		77,288

Total consideration		1,971,229
Cash received		31,231

Total consideration, net of cash received	$	1,939,998

⁽¹⁾

Property, plant and equipment consists of the following:


Pipelines and equipment (65 years)	$	1,051,211
Natural gas liquids storage (40 years)		356,242
Construction work-in-process		31,251

Property, plant and equipment	$	1,438,704

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and six months ended June 30, 2011 and 2010 are presented as if the acquisitions of LDH and Regency had been completed on January 1, 2010:


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Revenues	$	2,011,513	$	1,659,528	$	4,072,615	$	3,932,061
Net income		100,768		19,233		297,298		208,823
Net income attributable to partners		64,881		74,673		152,804		173,799
Basic net income per Limited Partner unit		0.29		0.33		0.69		0.78
Diluted net income per Limited Partner unit		0.29		0.33		0.69		0.78

The pro forma consolidated results of operations include adjustments to:

•

include the results of LDH and Regency 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 purchase price;

•

adjust for one-time expenses; and

•

adjust for relative changes in ownership resulting from both 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 periods presented or the future results of the combined operations.

The accounting for this transaction is based on the preliminary purchase price allocation, which is pending final working capital settlements.

Pending Acquisition

On July 19, 2011, we entered into a Second Amended and Restated Plan of Merger (the “Second Amended SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-owned subsidiary (“Merger Sub”), and Southern Union Company (“SUG”), a Delaware corporation. The Second Amended SUG Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011. Under the terms of the Second Amended SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary (the “SUG Merger”) subject to certain conditions to close. Pursuant to the Second Amended SUG Merger Agreement, ETE would acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.

Consummation of the SUG Merger is subject to customary conditions, including, without limitation: (i) the adoption of the Second Amended SUG Merger Agreement by the stockholders of SUG, (ii) the expiration or early termination of the waiting period applicable to the SUG Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the “HSR Act”), as amended, and any required approvals thereunder, (iii) the receipt of required approvals from the Federal Energy Regulatory Commission (“FERC”), the Missouri Public Service Commission and, if required, the Massachusetts Department of Public Utilities, (iv) the effectiveness of a registration statement on Form S-4 relating to the ETE Common Units to be issued in the SUG Merger, and (v) the absence of any law, injunction, judgment or ruling prohibiting or restraining the SUG Merger or making the consummation of the SUG Merger illegal. On July 28, 2011, the waiting period applicable to the SUG Merger under the HSR Act expired.

Citrus Transaction

On July 19,2011, ETP entered into an Amended and Restated Agreement and Plan of Merger with us (the “Amended Citrus Merger Agreement”). The Amended Citrus Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by ETP and us on July 4, 2011. Pursuant to the terms of the Second Amended SUG Merger Agreement, immediately prior to the effective time of the SUG Merger, we will assign and SUG will assume the benefits and obligations of us under the Amended Citrus Merger Agreement.

Under the Amended Citrus Merger Agreement, it is anticipated that SUG will cause the contribution to ETP of a 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission pipeline system and is currently jointly owned by SUG and El Paso Corporation (the “Citrus Transaction”). The Citrus Transaction will be effected through the merger of Citrus ETP Acquisition, L.L.C., a Delaware limited liability company and wholly-owned subsidiary of SUG that indirectly owns a 50% interest in Citrus Corp. (“CrossCountry”). In exchange for the interest in Citrus Corp., SUG will receive approximately $2.0 billion, consisting of $1.895 billion in cash and $105 million of ETP Common Units, with the value of the ETP Common Units based on the volume-weighted average trading price for the 10 consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Transaction. In order to increase the expected accretion to be derived from the Citrus Transaction, we have agreed to relinquish our rights to approximately $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the transaction.

The Amended Citrus Merger Agreement includes customer representations, warranties and covenants of ETP and us (including representations, warranties and covenants relating to SUG, CrossCountry and certain of CrossCountry’s affiliates). Consummation of the Citrus Transaction is subject to customary conditions, including, without limitation: (i) satisfaction or waiver of the closing conditions set forth in the Second Amended SUG Merger Agreement, (ii) the receipt by ETP of any necessary waivers or amendments to its credit agreements, (iii) the amendment of ETP’s partnership agreement to reflect the agreed upon relinquishment by us of incentive distributions from ETP discussed above, and (iv) the absence of any order, decree, injunction or law prohibiting or making the consummation of the transactions contemplated by the Amended Citrus Merger Agreement illegal. The Amended Citrus Merger Agreement contains certain termination rights for both us and ETP, including among others, the right to terminate if the Citrus Transaction is not completed by December 31, 2012 or if the Second Amended Merger SUG Agreement is terminated.

Pursuant to the Amended Citrus Merger Agreement, we have has granted ETP a right of first offer with respect to any disposition by us or SUG of Southern Union Gas Services, a subsidiary of SUG that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.

4.	CASH AND CASH EQUIVALENTS:

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

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.

The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:


	Six Months Ended June 30,
	2011			2010
Accounts receivable	$	40,057		$	98,321
Accounts receivable from related companies		(38,515	)		21,603
Inventories		30,181			159,540
Exchanges receivable		2,599			13,151
Other current assets		(19,484	)		35,792
Intangibles and other assets		4,241			4,201
Accounts payable		(31,956	)		(66,853	)
Accounts payable to related companies		23,902			(12,096	)
Exchanges payable		2,970			(7,880	)
Accrued and other current liabilities		17,892			38,036
Other non-current liabilities		11,108			(583	)
Price risk management assets and liabilities, net		(21,794	)		53,085

Net change in operating assets and liabilities, net of effects of acquisitions	$	21,201		$	336,317

Non-cash investing activities are as follows:


	Six Months Ended June 30,
	2011		2010
Accrued capital expenditures	$	106,047	$	73,432

Gain from subsidiary common unit transactions	$	92,074	$	280,492

5.	INVENTORIES:

Inventories consisted of the following:


	June 30, 2011		December 31, 2010
Natural gas and NGLs, excluding propane	$	176,093	$	170,179
Propane		59,213		76,341
Appliances, parts and fittings and other		112,871		119,864

Total inventories	$	348,177	$	366,384

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

6.	GOODWILL, INTANGIBLES AND OTHER ASSETS:

A net increase in goodwill of $408.3 million was recorded during the six months ended June 30, 2011 primarily due to the LDH Acquisition referenced in Note 3. This additional goodwill is expected to be deductible for tax purposes. In addition, ETP recorded customer contracts of $83.0 million with useful lives ranging from 3 to 14 years.

Components and useful lives of intangibles and other assets were as follows:


	June 30, 2011					December 31, 2010
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	1,053,788	$	(109,657	)	$	971,657	$	(88,583	)
Trade names (20 years)		65,500		(2,993	)		65,500		(1,910	)
Noncompete agreements (3 to 15 years)		20,187		(12,219	)		21,165		(11,888	)
Patents (9 years)		750		(160	)		750		(118	)
Other (10 to 15 years)		1,320		(544	)		1,320		(492	)

Total amortizable intangible assets		1,141,545		(125,573	)		1,060,392		(102,991	)
Non-amortizable intangible assets:
Trademarks		77,655		—			77,445		—

Total intangible assets		1,219,200		(125,573	)		1,137,837		(102,991	)
Other assets:
Financing costs (3 to 30 years)		157,882		(47,140	)		137,012		(38,945	)
Regulatory assets		107,258		(16,381	)		107,384		(14,445	)
Other		31,136		(658	)		35,001		(426	)

Total intangibles and other assets	$	1,515,476	$	(189,752	)	$	1,417,234	$	(156,807	)

Aggregate amortization expense of intangibles and other assets was as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Reported in depreciation and amortization	$	12,204	$	7,910	$	25,345	$	13,056

Reported in interest expense	$	5,005	$	3,728	$	9,577	$	6,645

Estimated aggregate amortization expense for the next five years is as follows:


Years Ending December 31:
2012	$	70,449
2013		65,243
2014		62,222
2015		57,776
2016		56,250

7.	FAIR VALUE MEASUREMENTS:

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

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 June 30, 2011 was $12.02 billion and $11.15 billion, respectively. As of December 31, 2010, the aggregate fair value and carrying amount of our consolidated debt obligations was $10.23 billion and $9.38 billion, respectively.

We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Preferred Units of a Subsidiary (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 over-the-counter (“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 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2011 and December 31, 2010 based on inputs used to derive their fair values:


	Fair Value Measurements at June 30, 2011 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	1,996		$	1,996		$	—		$	—
Interest rate derivatives		18,854			—			18,854			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		81,744			81,744			—			—
Swing Swaps IFERC		8,258			1,371			6,887			—
Fixed Swaps/Futures		19,819			18,445			1,374			—
Options — Puts		14,956			—			14,956			—
NGLs — Forward Swaps		67			—			67			—
Propane — Forward Swaps		557			—			557			—

Total commodity derivatives		125,401			101,560			23,841			—

Total Assets	$	146,251		$	103,556		$	42,695		$	—


Liabilities:
Interest rate derivatives	$	(9,753	)	$	—		$	(9,753	)	$	—
Preferred Units		(334,170	)		—			—			(334,170	)
Embedded derivatives in the Regency Preferred Units		(51,498	)		—			—			(51,498	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		(79,164	)		(79,164	)		—			—
Swing Swaps IFERC		(11,040	)		(2,682	)		(8,358	)		—
Fixed Swaps/Futures		(16,760	)		(16,760	)		—			—
Options — Puts		(27	)		—			(27	)		—
Options — Calls		(704	)		—			(704	)		—
NGLs — Forward Swaps		(16,711	)		—			(16,711	)		—
Propane — Forward Swaps		(281	)		—			(281	)		—
WTI Crude Oil		(3,651	)		—			(3,651	)		—

Total commodity derivatives		(128,338	)		(98,606	)		(29,732	)		—

Total Liabilities	$	(523,759	)	$	(98,606	)	$	(39,485	)	$	(385,668	)


	Fair Value Measurements at December 31, 2010 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	2,032		$	2,032		$	—		$	—
Interest rate derivatives		20,790			—			20,790			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		15,756			15,756			—			—
Swing Swaps IFERC		1,682			1,562			120			—
Fixed Swaps/Futures		44,955			42,474			2,481			—
Options — Calls		75			—			75			—
Options — Puts		26,241			—			26,241			—
NGLs — Forward Swaps		192			—			192			—
Propane — Forward Swaps		6,864			—			6,864			—

Total commodity derivatives		95,765			59,792			35,973			—

Total Assets	$	118,587		$	61,824		$	56,763		$	—


Liabilities:
Interest rate derivatives	$	(20,922	)	$	—		$	(20,922	)	$	—
Preferred Units		(317,600	)		—			—			(317,600	)
Embedded derivatives in the Regency Preferred Units		(57,023	)		—			—			(57,023	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		(17,372	)		(17,372	)		—			—
Swing Swaps IFERC		(3,768	)		(3,520	)		(248	)		—
Fixed Swaps/Futures		(42,252	)		(41,825	)		(427	)		—
Options — Calls		(2,643	)		—			(2,643	)		—
Options — Puts		(7	)		—			(7	)		—
NGLs — Forward Swaps		(10,684	)		—			(10,684	)		—
WTI Crude Oil		(3,581	)		—			(3,581	)		—

Total commodity derivatives		(80,307	)		(62,717	)		(17,590	)		—

Total Liabilities	$	(475,852	)	$	(62,717	)	$	(38,512	)	$	(374,623	)

The following table presents a reconciliation of the beginning and ending balances for liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the six months ended June 30, 2011. There were no transfers between the fair value hierarchy levels during the six months ended June 30, 2011.


Balance, December 31, 2010	$	(374,623	)
Net unrealized losses included in other income (expense)		(11,045	)

Balance, June 30, 2011	$	(385,668	)

8.	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 June 30,					Six Months Ended June 30,
	2011			2010		2011			2010
Basic Net Income per Limited Partner Unit:

Limited Partners’ interest in net income	$	66,080		$	19,208	$	154,446		$	131,636


Weighted average Limited Partner units		222,972,708			222,941,172		222,963,741			222,941,140


Basic net income per Limited Partner unit	$	0.30		$	0.09	$	0.69		$	0.59


Diluted Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	66,080		$	19,208	$	154,446		$	131,636
Dilutive effect of equity-based compensation of subsidiaries		(132	)		—		(402	)		(131	)

Diluted net income available to Limited Partners	$	65,948		$	19,208	$	154,044		$	131,505


Weighted average Limited Partner units		222,972,708			222,941,172		222,963,741			222,941,140


Diluted net income per Limited Partner unit	$	0.30		$	0.09	$	0.69		$	0.59

Discontinued operations per unit has been omitted as the impact rounds to $0.00 per unit for all relevant periods presented.

The calculation above for the three and six months ended June 30, 2011 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 $300.0 million and are subject to mandatory conversion as discussed in Note 10.

9.	DEBT OBLIGATIONS:

Senior Notes

ETP Senior Notes

In May 2011, ETP completed a public offering of $800 million aggregate principal amount of 4.65% Senior Notes due June 1, 2021 and $700 million aggregate principal amount of 6.05% Senior Notes due June 1, 2041. ETP used the proceeds, net of commissions, of $1.48 billion to repay all of the borrowings outstanding under its revolving credit facility (the “ETP Credit Facility”), to fund capital expenditures related to pipeline construction projects 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.

Regency Senior Notes

In May 2011, Regency issued $500.0 million aggregate principal amount of 6.5% Senior Notes due July 15, 2021 (the “Regency 2021 Notes”). Regency used the proceeds, net of commissions, of approximately $491.3 million to repay borrowings outstanding under its revolving credit facility (the “Regency Credit Facility”). Regency capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the Regency 2021 Notes. Interest will be paid semi-annually.

At any time prior to July 15, 2016, Regency may redeem some or all of the Regency 2021 Notes at a redemption price equal to 100% of the principal amount plus a “make-whole” premium, plus accrued and unpaid interest to the redemption date. At any time before July 15, 2014, Regency may redeem up to 35% of the aggregate principal amount of the Regency 2021 Notes then outstanding

at a redemption price equal to 106.5% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the redemption date.

Upon the occurrence of a change of control event, as defined in the indenture, followed by a rating decline within 90 days, each holder of the Regency 2021 Notes will be entitled to require Regency to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. Regency’s ability to purchase the notes upon a change of control will be limited by the terms of its debt agreements, including Regency’s revolving credit facility.

The Regency 2021 Notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries to:

•

incur additional indebtedness;

•

pay distributions on, or repurchase or redeem equity interests;

•

make certain investments;

•

incur liens;

•

enter into certain types of transactions with affiliates; and

•

sell assets, consolidate or merge with or into other companies.

Revolving Credit Facilities

Parent Company Credit Agreement

The Parent Company has a $200 million senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. The Parent Company Credit Agreement is secured by all tangible or intangible assets of ETE and certain of its subsidiaries. As of June 30, 2011, there were no outstanding borrowings under the Parent Company Credit Agreement.

ETP Credit Facility

The ETP Credit Facility provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity). The ETP Credit Facility matures on July 20, 2012, unless ETP elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). As of June 30, 2011, ETP had a balance of $144.0 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.81 billion taking into account letters of credit of $42.9 million. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 0.76%.

Regency Credit Facility

The Regency Credit Facility has aggregate revolving commitments of $900 million that matures June 15, 2014. As of June 30, 2011, there was a balance outstanding under the Regency Credit Facility of $330.0 million in revolving credit loans and approximately $11.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of June 30, 2011, which is reduced by any letters of credit, was approximately $559.0 million. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 3.25%.

Covenants Related to Our Credit Agreements

We, ETP and Regency are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of June 30, 2011.

10.

REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

In connection with the Regency Transactions completed in May 2010, ETE issued 3,000,000 Series A Convertible Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300.0 million and were reflected as a non-current liability in our consolidated balance sheets as of June 30, 2011 and December 31, 2010. The Series A Convertible 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 has 4,371,586 Regency Preferred Units outstanding at June 30, 2011, which were convertible into 4,620,152 Regency Common Units. If outstanding on September 2, 2029, the Regency Preferred Units are mandatorily redeemable for $80.0 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed quarterly cash distributions of $0.445 per unit from Regency. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s Partnership Agreement.

The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:


	Regency Preferred Units		Amount
Balance as of December 31, 2010		4,371,586	$	70,943
Accretion to redemption value		—		97

Ending balance as of June 30, 2011		4,371,586	$	71,040

11.

EQUITY:

Common Units Issued

The change in ETE Common Units during the six months ended June 30, 2011 was as follows:


	Number of Units
Balance, December 31, 2010		222,941,172
Issuance of restricted common units under equity incentive plans		31,536

Balance, June 30, 2011		222,972,708

Sales of Common Units by Subsidiaries

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

As a result of ETP’s and Regency’s issuances of Common Units during the six months ended June 30, 2011, we recognized increases in partners’ capital of $92.1 million.

Sale of Common Units by ETP

On April 1, 2011, ETP issued 14,202,500 Common Units through a public offering. The proceeds, net of commissions, of approximately $695.5 million were used to repay amounts outstanding under the ETP Credit Facility, to fund capital expenditures related to pipeline construction projects and for general partnership purposes.

ETP has an Equity Distribution Agreement with Credit Suisse Securities (USA) LLC (“Credit Suisse”) under which ETP may offer and sell from time to time through Credit Suisse, as its sales agent, ETP Common Units having an aggregate offering price of up to $200.0 million. During the six months ended June 30, 2011, ETP received proceeds from units issued pursuant to this agreement of approximately $72.9 million, net of commissions, which were used for general partnership purposes. Approximately $101.2 million of ETP Common Units remain available to be issued under the Equity Distribution Agreement based on trades initiated through June 30, 2011.

In April 2011, ETP filed a registration statement with the SEC covering ETP’s Distribution Reinvestment Plan (the “DRIP”). The DRIP provides Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units. Currently, the registration statement covers the issuance of up to 5,750,000 ETP Common Units under the DRIP.

In May 2011, in conjunction with the payment of ETP’s distribution for the quarter ended March 31, 2011, distributions of approximately $1.9 million were reinvested under the DRIP resulting in the issuance of 41,139 ETP Common Units.

Sale of Common Units by Regency

In May 2011, Regency issued 8,500,001 Regency Common Units in a private placement. The net proceeds of $203.9 million from the from the private placement were used to fund a portion of Regency’s 30% ownership interest in Lone Star, as discussed in Note 3.

Parent Company Quarterly Distributions of Available Cash

The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partnership interests, including IDRs. We currently have no independent operations outside of our interests in ETP and Regency.

Following are distributions declared and/or paid by us subsequent to December 31, 2010:


Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 18, 2011	$0.540
March 31, 2011	May 6, 2011	May 19, 2011	0.560
June 30, 2011	August 5, 2011	August 19, 2011	0.625

The distribution for the quarter ended June 30, 2011 was announced on June 30, 2011 and was reflected as an accrued distribution to ETE partners on our consolidated balance sheet as of June 30, 2011.

ETP’s Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2010:


Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 14, 2011	$0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375

Regency’s Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2010:


Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 14, 2011	$0.445
March 31, 2011	May 6, 2011	May 13, 2011	0.445
June 30, 2011	August 5, 2011	August 12, 2011	0.450

Accumulated Other Comprehensive Income (Loss)

The following table presents the components of accumulated other comprehensive (loss) income (“AOCI”), net of tax:


	June 30, 2011			December 31, 2010
Net gains on commodity related hedges	$	(6,279	)	$	14,146
Unrealized gains on available-for-sale securities		883			918

Subtotal		(5,396	)		15,064
Amounts attributable to noncontrolling interest		5,040			(10,266	)

Total AOCI included in partners’ capital, net of tax	$	(356	)	$	4,798

12.

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, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

During the six months ended June 30, 2011, ETE employees were granted a total of 30,000 unvested awards with five-year service vesting requirements. The weighted average grant-date fair value of these awards was $39.82 per unit. As of June 30, 2011 a total of 105,713 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $1.7 million in compensation expense over a weighted average period of 2.1 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the six months ended June 30, 2011, ETP employees were granted a total of 518,700 unvested awards with five-year service vesting requirements, and directors were granted a total of 2,580 unvested awards with three-year service vesting requirements. The weighted average grant-date fair value of these awards was $53.60 per unit. As of June 30, 2011 a total of 2,450,698 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $69.2 million in compensation expense over a weighted average period of 1.7 years related to unvested awards.

Regency Unit-Based Compensation Plans

Common Unit Options

During the six months ended June 30, 2011, no Regency Common Unit options were granted. As of June 30, 2011, a total of 166,050 Regency Common Unit options remain vested and exercisable, with a weighted average exercise price of $22.13 per Regency Common Unit option.

Phantom Units

During the six months ended June 30, 2011, Regency employees and directors were granted 68,745 Regency phantom units with three-year service vesting requirements. As of June 30, 2011, a total of 718,172 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.77. We expect to recognize a total of $13.0 million in compensation expense over a weighted average period of 4.2 years related to Regency’s unvested phantom units.

13.

INCOME TAXES:

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Current expense:
Federal	$	561		$	1,739		$	5,663		$	3,057
State		5,439			4,344			9,435			7,502

Total current expense		6,000			6,083			15,098			10,559


Deferred expense (benefit):
Federal		(747	)		(1,723	)		(559	)		(1,029	)
State		(29	)		(307	)		588			(266	)

Total deferred expense (benefit)		(776	)		(2,030	)		29			(1,295	)

Total income tax expense	$	5,224		$	4,053		$	15,127		$	9,264

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level.

14.

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Guarantee — Fayetteville Express Pipeline LLC

Fayetteville Express Pipeline LLC (“FEP”), a joint venture entity in which ETP owns a 50% interest, had a credit agreement that provided for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by Kinder Morgan Energy Partners, L.P. (“KMP”). Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate.

As of June 30, 2011, FEP had $968.5 million of outstanding borrowings issued under the FEP Facility and ETP’s contingent obligation with respect to its guaranteed portion of FEP’s outstanding borrowings was $484.3 million, which was not reflected in our consolidated balance sheet. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 3.09%.

In July 2011, the FEP Facility was repaid with capital contributions from ETP and KMP totaling $390 million along with proceeds from a $600 million term loan credit facility maturing in July 2012 (which can be extended for one year at the option of FEP). Upon closing and funding of the term loan facility, the FEP Facility was terminated. FEP also entered into a $50 million revolving credit facility maturing in July 2015. ETP does not guarantee FEP’s indebtedness under its term loan or new credit facility.

NGL Pipeline Regulation

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

Commitments

In the normal course of our business, ETP and Regency 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. ETP has also entered into several propane purchase and supply commitments, which are typically one year agreements with varying terms as to quantities, prices and expiration dates. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its 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 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $7.8 million and $5.8 million for the three months ended June 30, 2011 and 2010. For the six months ended June 30, 2011 and 2010, rental expense for operating leases totaled approximately $13.2 million and $11.7 million, respectively.

ETP’s propane operations have an agreement with Enterprise Products Partners L.P. (together with its subsidiaries “Enterprise”) (see Note 16) to supply a portion of its propane requirements. The agreement will continue until March 2015 and includes an option to extend the agreement for an additional year.

In connection with the sale of ETP’s investment in M-P Energy in October 2007, ETP executed a propane purchase agreement for approximately 90.0 million gallons per year through 2015 at market prices plus a nominal fee.

ETP’s and Regency’s joint venture agreements require that ETP and Regency fund their proportionate shares of capital contributions to their unconsolidated affiliates. ETP and Regency expect that such capital contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and propane 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 June 30, 2011 and December 31, 2010, accruals of approximately $10.7 million and $10.2 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty, and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Further, 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 June 30, 2011 or December 31, 2010 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that can 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 operations are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the U.S. Department of Transportation (“DOT”). We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

ETP Environmental Matters

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 ETP’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, ETP believes that such costs will not have a material adverse effect on its financial position.

As of June 30, 2011 and December 31, 2010, accruals related to ETP on an undiscounted basis of $12.8 million and $13.8 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.

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

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”). The costs of this work are not eligible for recovery in rates. ETP’s total accrued future estimated cost of remediation activities expected to continue through 2025 is $8.1 million, which is included in the aggregate environmental accruals discussed above. Transwestern received approval from the FERC for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

The U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of ETP’s facilities. ETP is currently reviewing the impact to its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but ETP believes such costs will not have a material adverse effect on its financial position, results of operations or cash flows.

Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, nor has its operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our June 30, 2011 consolidated balance sheets or our December 31, 2010 consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

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 ETP to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. On October 19, 2010, industry groups submitted a legal challenge to the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to EPA for some monitoring aspects of the rule. The legal challenge has been held in abeyance since December 3, 2010, pending EPA’s consideration of the Petition for Administrative Reconsideration. On January 5, 2011, the EPA approved the request for reconsideration of the monitoring issues and on March 9, 2011, 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 significant adverse comments are filed on the direct final rule, EPA would address public comments in a subsequent final rule. At this point, we cannot predict how the direct final rule might be modified as a result of the comments received or a future court ruling and as a result we cannot currently accurately predict the cost to comply with the rule’s requirements. Compliance with the final rule is required by October 2013.

On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule will become effective on August 29, 2011. The rule modifications may require ETP to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if it replaces equipment or expands existing facilities in the future. At this point, ETP is not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes ETP might make in the future.

ETP’s pipeline operations are subject to regulation by the DOT under the Pipeline Hazardous Materials Safety Administration (“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. For the three months ended June 30, 2011 and 2010, $3.9 million and $3.6 million, respectively, of capital costs and $3.9 million and $4.4 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. For the six months ended June 30, 2011 and 2010, $5.6 million and $5.0 million, respectively, of capital costs and $6.0 million and $6.3 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

15.

PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane 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 segment as well as tables detailing the outstanding commodity-related derivatives as of June 30, 2011 and December 31, 2010 by segment.

Investment in 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 the consolidated statements of operations.

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 itself from the 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. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance ETP’s 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’s propane operations permit customers to guarantee the propane delivery price for the next heating season. As ETP executes fixed sales price contracts with its customers, it may enter into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin. Additionally, ETP may use propane futures contracts to secure the purchase price of its propane inventory for a percentage of its anticipated propane sales.

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


	June 30, 2011				December 31, 2010
	Notional Volume			Maturity	Notional Volume			Maturity
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)		(26,145,000	)	2011-2013		(38,897,500	)	2011
Swing Swaps IFERC (MMBtu)		(144,420,000	)	2011-2012		(19,720,000	)	2011
Fixed Swaps/Futures (MMBtu)		6,695,000		2011-2012		(2,570,000	)	2011
Options — Calls (MMBtu)		—		—		(3,000,000	)	2011
Propane:
Forwards/Swaps (Gallons)		—		—		1,974,000		2011

Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)		(26,040,000	)	2011-2012		(28,050,000	)	2011
Fixed Swaps/Futures (MMBtu)		(38,285,000	)	2011-2012		(39,105,000	)	2011
Hedged Item — Inventory (MMBtu)		38,285,000		2011		39,105,000		2011

Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)		920,000		2011		(210,000	)	2011
Options — Puts (MMBtu)		15,180,000		2011-2012		26,760,000		2011-2012
Options — Calls (MMBtu)		(15,180,000	)	2011-2012		(26,760,000	)	2011-2012
Propane:
Forwards/Swaps (Gallons)		14,700,000		2011-2012		32,466,000		2011

We expect gains of $10.4 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Investment in Regency

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

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’s General Partner have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency’s General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of Regency’s General Partner is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency’s Risk Management 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 10) 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 affect its cash flows.

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


	June 30, 2011			December 31, 2010
	Notional Volume		Maturity	Notional Volume		Maturity
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)		3,670,000	2011-2012		3,830,000	2011
Propane:
Forwards/Swaps (Gallons)		18,564,000	2011-2013		18,648,000	2011-2012
Natural Gas Liquids:
Forwards/Swaps (Barrels)		1,006,000	2011-2013		1,212,110	2011-2012
WTI Crude Oil:
Forwards/Swaps (Barrels)		483,000	2011-2014		373,655	2011-2012

We expect gains of $16.4 million related to Regency’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.

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 variable rate debt. We manage our current interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. The following is a summary of interest rate swaps outstanding as of June 30, 2011 and December 31, 2010, none of which were designated as hedges for accounting purposes:

Notional Amount
Outstanding

Entity

Term

Type ⁽¹⁾

June 30,
2011

December 31,
2010

ETP

August 2012⁽²⁾

Forward starting to pay a fixed rate of 3.64% and receive a floating rate

400,000

ETP

July 2013⁽³⁾

Forward starting to pay a fixed rate of 4.13% and receive a floating rate

200,000

—

ETP

July 2018

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

500,000

Regency

April 2012

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

250,000

⁽¹⁾

Floating rates are based on LIBOR.

⁽²⁾

These forward starting swaps have an effective date of August 2012 and a term of 10 years; however, the swaps have a mandatory termination provision and will be settled in August 2012.

⁽³⁾

These forward starting swaps have an effective date of July 2013 and a term of 10 years; however, the swaps have a mandatory termination provision and will be settled in July 2013.

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 counterparty.

Our counterparties consist primarily of petrochemical companies, other industrial, mid-size to major oil and gas companies and power 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 performance.

ETP utilizes master-netting agreements and has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in our consolidated balance sheets. ETP had net deposits with counterparties of $60.9 million and $52.2 million as of June 30, 2011 and December 31, 2010, respectively.

Regency is exposed to credit risk from its derivative counterparties. Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

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 June 30, 2011 and December 31, 2010:


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	June 30, 2011		December 31, 2010		June 30, 2011			December 31, 2010
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	23,729	$	35,031	$	(2,136	)	$	(6,631	)
Commodity derivatives		2,001		9,263		(20,696	)		(14,692	)

		25,730		44,294		(22,832	)		(21,323	)


Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	111,866	$	64,940	$	(117,701	)	$	(72,729	)
Commodity derivatives		—		275		—			—
Interest rate derivatives		18,854		20,790		(9,753	)		(20,922	)
Embedded derivatives in Regency Preferred Units		—		—		(51,498	)		(57,023	)

		130,720		86,005		(178,952	)		(150,674	)

Total derivatives	$	156,450	$	130,299	$	(201,784	)	$	(171,997	)

The commodity derivatives (margin deposits) are recorded in “Other current assets” on our consolidated balance sheets. The remainder of the derivatives are recorded in “Price risk management assets/liabilities.”

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

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


	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011			2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	3,769	$	(9,150	)	$	(7,123	)	$	24,957
Interest rate derivatives		—		(9,955	)		—			(20,155	)

Total	$	3,769	$	(19,105	)	$	(7,123	)	$	4,802



	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(2,148	)	$	7,058		$	12,954	$	12,373
Interest rate derivatives	Interest expense		—			(8,619	)		—		(15,885	)

Total		$	(2,148	)	$	(1,561	)	$	12,954	$	(3,512	)


	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	96		$	(1,016	)	$	189	$	105

Total		$	96		$	(1,016	)	$	189	$	105


	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/ (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011		2010
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	15,874		$	6,417		$	22,291	$	(967	)

Total		$	15,874		$	6,417		$	22,291	$	(967	)


	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011			2010
Derivatives not designated as hedging instruments:
Commodity derivatives	Cost of products sold	$	(11,427	)	$	(22,119	)	$	(4,989	)	$	(152	)
Interest rate derivatives	Gains (losses) on non-hedged interest rate derivatives		1,883			(22,468	)		3,403			(36,892	)
Embedded Derivatives	Other income (expenses)		2,950			(3,606	)		5,525			(3,606	)

Total		$	(6,594	)	$	(48,193	)	$	3,939		$	(40,650	)

We recognized $15.7 million and $38.8 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 June 30, 2011 and 2010, respectively. We recognized $2.1 million and $47.5 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 six months ended June 30, 2011 and 2010, respectively. In addition, for the three months ended June 30, 2011 and 2010, we recognized unrealized gains of $16.7 million and unrealized losses of $8.2 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges. For the six months ended June 30, 2011 and 2010, we recognized unrealized gains of $7.8 million and $25.0 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges.

16.

RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. For the three and six months ended June 30, 2011, the Parent Company received $4.2 million and $8.1 million in management fees from Regency related to these services. For the three and six months ended June 30, 2011, the Parent Company paid $3.4 million and $8.4 million in management fees, respectively, to ETP related to these services. For the three and six months ended June 30, 2010, the Parent Company paid $0.1 million and $0.3 million in management fees, respectively, to ETP related to these services. The management fees received from Regency for the three and six months ended June 30, 2011 reflect the reimbursement of various general and administrative services of $0.8 million and $3.1 million, respectively, for expenses incurred by ETP on behalf of Regency.

Enterprise and its subsidiaries currently hold a portion of our limited partner interest. As a result, Enterprise and its affiliates are considered related parties for financial reporting purposes.

ETP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ETP sells natural gas to Enterprise. ETP’s propane operations purchase a portion of its propane requirements from Enterprise pursuant to an agreement that expires in March 2015 and includes an option to extend the agreement for an additional year. Regency sells natural gas and NGLs to, and incurs NGL processing fees with Enterprise. The following table presents sales to and purchases from Enterprise:


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
ETP’s Natural Gas Operations:
Sales	$	162,107	$	130,526	$	298,020	$	275,246
Purchases		9,736		6,936		17,960		13,533

Regency’s Natural Gas Operations:
Sales		81,055		18,501		155,969		18,501
Purchases		3,319		422		2,998		422

ETP’s Propane Operations:
Sales		1,441		481		10,218		10,966
Purchases		72,191		52,415		242,157		218,179

As of December 31, 2010, a subsidiary of ETP, had forward mark-to-market derivatives with Enterprise for approximately 1.7 million gallons of propane for a fair value asset of $0.2 million. These forward contracts were settled as of June 30, 2011. In addition, as of June 30, 2011 and December 31, 2010, a subsidiary of ETP had forward derivatives accounted for as cash flow hedges of 14.7 million and 32.5 million gallons of propane at fair value assets of $0.3 million and $6.6 million, respectively, with Enterprise.

Under a master services agreement with RIGS Haynesville Partnership Co. (“HPC”), Regency operates and provides all employees and services for the operation and management of HPC. The related party general administrative expenses reimbursed to Regency were $4.2 million and $8.4 million for the three and six months ended June 30, 2011. For the period from May 26, 2010 to June 30, 2010, the related party general administrative expenses reimbursed to Regency were $1.4 million.

Regency’s contract compression operations provide contract compression services to HPC. HPC also provides transportation service to Regency. For the three and six months ended June 30, 2011, Regency had revenue of $6.5 million and $13.0 million, respectively, and cost of sales of $4.0 million and $8.1 million, respectively, with HPC.

The following table summarizes the related party balances on our consolidated balance sheets:


	June 30, 2011			December 31, 2010
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	50,180		$	36,736
Regency’s Natural Gas Operations		18,649			25,539
ETP’s Propane Operations		226			2,327
Other		13,455			11,729

Total accounts receivable from related parties:	$	82,510		$	76,331

Accounts payable to related parties:
Enterprise:
ETP’s Natural Gas Operations	$	1,749		$	2,687
Regency’s Natural Gas Operations		754			1,323
ETP’s Propane Operations		10,830			22,985
Other		1,552			356

Total accounts payable to related parties:	$	14,885		$	27,351

ETP’s net imbalance receivable from Enterprise	$	592		$	1,360

Regency’s net imbalance (payable to) receivable from Enterprise	$	(774	)	$	753

17.

OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:


	June 30, 2011		December 31, 2010
Deposits paid to vendors	$	60,861	$	52,192
Prepaid expenses and other		81,473		57,167

Total other current assets	$	142,334	$	109,359

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	June 30, 2011		December 31, 2010
Interest payable	$	191,206	$	191,466
Customer advances and deposits		63,111		111,448
Accrued capital expenditures		97,702		87,260
Accrued wages and benefits		59,812		76,592
Taxes payable other than income taxes		78,271		36,204
Income taxes payable		2,421		8,344
Other		97,239		56,374

Total accrued and other current liabilities	$	589,762	$	567,688

18.

REPORTABLE SEGMENTS:

Our reportable segments reflect two reportable segments, both of 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 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 operating segments based on net income. The following tables present financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Related party transactions between ETP and Regency 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			Adjustments and Eliminations			Total
Three months ended June 30, 2011:
Revenues from external customers	$	1,616,748	$	354,816		$	—		$	3,342		$	1,974,906
Intersegment revenues		11,347		1,682			—			(13,029	)		—
Income tax expense (benefit)		5,783		102			(661	)		—			5,224
Net income (loss)		156,616		14,837			(56,413	)		(8,388	)		106,652

Three months ended June 30, 2010:
Revenues from external customers	$	1,267,706	$	96,082		$	—		$	(1,260	)	$	1,362,528
Intersegment revenues		—		898			—			(898	)		—
Income tax expense (benefit)		4,569		245			(761	)		—			4,053
Net income (loss)		42,843		(4,895	)		(58,427	)		—			(20,479	)

Six months ended June 30, 2011:
Revenues from external customers	$	3,292,795	$	670,375		$	—		$	856		$	3,964,026
Intersegment revenues		22,877		3,375			—			(26,252	)		—
Income tax expense (benefit)		16,380		70			(1,323	)		—			15,127
Net income (loss)		403,818		29,142			(118,828	)		(8,388	)		305,744

Six months ended June 30, 2010:
Revenues from external customers	$	3,139,687	$	96,082		$	—		$	(1,260	)	$	3,234,509
Intersegment revenues		—		898			—			(898	)		—
Income tax expense (benefit)		10,493		245			(1,474	)		—			9,264
Net income (loss)		282,954		(4,895	)		(94,456	)		—			183,603


	As of June 30, 2011			As of December 31, 2010
Total assets:
Investment in ETP	$	14,641,403		$	12,149,992
Investment in Regency		5,428,129			4,770,204
Corporate and Other		450,222			469,221
Adjustments and Eliminations		(653,596	)		(10,687	)

Total	$	19,866,158		$	17,378,730

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

Investment in ETP


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Intrastate Transportation and Storage	$	643,653	$	530,174	$	1,232,331	$	1,132,530
Interstate Transportation		104,850		70,079		209,951		138,348
Midstream		516,499		407,123		929,694		1,025,830
NGL Transportation and Services		90,771		—		90,771		—
Retail Propane and Other Retail Propane Related		243,973		220,126		801,188		781,281
All Other		28,349		40,204		51,737		61,698

Total revenues	$	1,628,095	$	1,267,706	$	3,315,672	$	3,139,687

Investment in Regency


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Gathering and Processing	$	303,203	$	83,778	$	569,175	$	83,778
Joint Ventures		—		—		—		—
Contract Compression		38,072		12,054		76,508		12,054
Contract Treating		10,842		—		19,275		—
Corporate and Others		4,381		1,148		8,792		1,148

Total revenues	$	356,498	$	96,980	$	673,750	$	96,980

19.

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS

(unaudited)


	June 30, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	14,383		$	27,247
Accounts receivable from related companies		447			171
Other current assets		1,894			864

Total current assets		16,724			28,282

ADVANCES TO AND INVESTMENTS IN AFFILIATES		2,258,150			2,231,722
INTANGIBLES AND OTHER ASSETS, net		27,838			29,118

Total assets	$	2,302,712		$	2,289,122


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	304		$	—
Accounts payable to related companies		9,414			6,654
Accrued distributions to ETE partners		139,790			—
Accrued and other current liabilities		42,575			44,200

Total current liabilities		192,083			50,854

LONG-TERM DEBT, less current maturities		1,800,000			1,800,000
SERIES A CONVERTIBLE PREFERRED UNITS		334,170			317,600

COMMITMENTS AND CONTINGENCIES

EQUITY:
General Partner		88			520
Limited Partners		(23,273	)		115,350
Accumulated other comprehensive income (loss)		(356	)		4,798

Total partners’ capital (deficit)		(23,541	)		120,668

Total liabilities and partners’ equity	$	2,302,712		$	2,289,122

STATEMENTS OF OPERATIONS

(unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(12,037	)	$	(15,079	)	$	(13,879	)	$	(17,415	)

OTHER INCOME (EXPENSE):
Interest expense		(40,587	)		(20,210	)		(81,526	)		(36,916	)
Equity in earnings of affiliates		120,626			75,362			267,268			221,740
Losses on non-hedged interest rate derivatives		—			(20,753	)		—			(35,177	)
Other, net		(1,653	)		(88	)		(16,812	)		(212	)

INCOME BEFORE INCOME TAXES		66,349			19,232			155,051			132,020
Income tax expense (benefit)		64			(36	)		126			(25	)

NET INCOME		66,285			19,268			154,925			132,045
GENERAL PARTNER’S INTEREST IN NET INCOME		205			60			479			409

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	66,080		$	19,208		$	154,446		$	131,636

STATEMENTS OF CASH FLOWS

(unaudited)


	Six Months Ended June 30,
	2011			2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	233,152		$	233,100

CASH FLOWS FROM INVESTING ACTIVITIES
MEP Transaction		—			3,016

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		20,000			30,376
Principal payments on debt		(20,000	)		(19,122	)
Distributions to partners		(246,016	)		(241,524	)
Debt issuance costs		—			(5,846	)

Net cash used in financing activities		(246,016	)		(236,116	)

DECREASE IN CASH AND CASH EQUIVALENTS		(12,864	)		—
CASH AND CASH EQUIVALENTS, beginning of period		27,247			62

CASH AND CASH EQUIVALENTS, end of period	$	14,383		$	62

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, 2010 filed with the SEC on February 28, 2011. Additionally, Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”) 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

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 risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part II — Other Information – Item 1A. Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2010.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency Energy Partners, L.P. (“Regency”), Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

OVERVIEW

Energy Transfer Equity, L.P. is a publicly traded Delaware limited partnership that directly and indirectly owns equity interests in ETP and Regency, both publicly traded master limited partnerships engaged in diversified energy-related services.

At June 30, 2011, our equity interests consisted of:


	General Partner Interest (as a % of total partnership interest)			Incentive Distribution Rights (“IDRs”)			Common Units
ETP		1.6	%		100	%		50,226,967
Regency		1.9	%		100	%		26,266,791

The principal sources of the Parent Company’s cash flow are its direct and indirect investments in limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements, distributions to its partners and holders of the Series A Convertible Preferred Units (the “Preferred Units”) and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries.

The following is a brief description of our reportable segments:

•

Investment in ETP – ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arkansas, Arizona, Colorado, Louisiana, Mississippi, 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 three storage facilities located in Texas. ETP also holds a 70% interest in a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

•

Investment in Regency – Regency is a publicly traded Delaware limited partnership formed in 2005 engaged in the gathering, treating, processing, compressing and transportation of natural gas and NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas production 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 primarily located in 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 a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.

Recent Developments

Pending Acquisition

On July 19, 2011, we entered into a Second Amended and Restated Plan of Merger (the “Second Amended SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-owned subsidiary (“Merger Sub”), and Southern Union Company (“SUG”), a Delaware corporation. The Second Amended Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011. Under the terms of the Second Amended SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary (the “SUG Merger”) subject to certain conditions to close. Pursuant to the Second Amended SUG Merger Agreement, we would acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.

We have secured $3.7 billion in committed financing from Credit Suisse Securities (USA) LLC (“Credit Suisse”) to fund a portion of the cash consideration. Closing of this business combination is contingent upon several conditions, including regulatory approvals and a vote of SUG shareholders. We expect the transaction to close in the first quarter of 2012.

On July 19, 2011, ETP entered into an Amended Citrus Merger Agreement pursuant to which it is anticipated that SUG will cause the contribution to ETP of SUG’s 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission (“FGT”) pipeline system, in exchange for approximately $1.895 billion in cash and $105 million of ETP Common Units, contemporaneous with the completion of the merger between SUG and us pursuant to the Second Amended SUG Merger Agreement as described in Note 3 to our consolidated financial statements. Citrus Corp is currently jointly owned by SUG and El Paso Corporation. The FGT pipeline system has a capacity of 3.0 billion cubic feet per day and supplied approximately 63% of the natural gas consumed in Florida for 2010. FGT’s primary customers are utilities with strong investment grade credit ratings. FGT’s long-term contracts with these high credit quality customers are expected to increase ETP’s fee-based revenue stream.

Lone Star

Lone Star NGL LLC (“Lone Star”), ETP’s and Regency’s recently acquired 70% and 30%, respectively, joint venture announced plans to construct a 100,000 Bbls/d fractionator in Mont Belvieu, Texas. Total cost of the fractionator is expected to be approximately $375 million and is expected to be in service by early 2013.

Lone Star also announced the construction of an approximate 530-mile NGL pipeline that extends from Winkler County in West Texas to a processing plant in Jackson County, Texas. In addition, Lone Star has secured capacity on ETP’s recently-announced NGL pipeline from Jackson County to Mont Belvieu, Texas. The project is expected to be completed in the first quarter of 2013 for an estimated cost of $700 million, which will be funded by contributions from ETP and Regency that are reflective of their ownership interests.

Eagle Ford Expansion

In June 2011, Regency entered into agreements to provide gas and condensate gathering services for a producer in the Eagle Ford Shale and to construct facilities to perform these services, including a wellhead gathering system, at an expected cost to Regency of approximately $450 million. Capital expenditures are expected to be incurred primarily over the next three years and will initially be funded under Regency’s revolving credit facility. The expansion is scheduled for completion by 2014.

Tiger Pipeline Expansion

ETP recently completed construction of the 400 MMcf/d expansion of its Tiger pipeline. The Tiger pipeline expansion was placed in service on August 1, 2011, bringing the total capacity of the Tiger pipeline to 2.4 Bcf/d.

Results of Operations

We accounted for our May 26, 2010 acquisition of Regency (the “Regency Transactions”) using the purchase method of accounting. As a result, we consolidated the results of Regency and its consolidated subsidiaries since May 26, 2010. Consequently, this Management’s Discussion and Analysis of Financial Condition and Results of Operations does not include the results of operations of Regency and its consolidated subsidiaries for periods prior to the Regency Transactions.

Consolidated Results


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
Revenues	$	1,974,906		$	1,362,528		$	612,378		$	3,964,026		$	3,234,509		$	729,517
Cost of products sold		1,264,152			840,453			423,699			2,465,578			2,065,318			400,260

Gross margin		710,754			522,075			188,679			1,498,448			1,169,191			329,257
Operating expenses		222,717			179,745			42,972			443,413			350,493			92,920
Depreciation and amortization		148,530			98,035			50,495			287,786			184,366			103,420
Selling, general and administrative		78,946			65,038			13,908			142,445			116,147			26,298

Operating income		260,561			179,257			81,304			624,804			518,185			106,619
Interest expense, net of interest capitalized		(181,517	)		(129,036	)		(52,481	)		(349,446	)		(250,707	)		(98,739	)
Equity in earnings of affiliates		28,819			12,193			16,626			54,260			18,374			35,886
Gains (losses) on disposal of assets		(681	)		1,375			(2,056	)		(2,435	)		(489	)		(1,946	)
Gains (losses) on non-hedged interest rate derivatives		1,883			(22,468	)		24,351			3,403			(36,892	)		40,295
Impairment of investment in affiliate		—			(52,620	)		52,620			—			(52,620	)		52,620
Other, net		2,811			(5,213	)		8,024			(9,715	)		(3,070	)		(6,645	)
Income tax expense		(5,224	)		(4,053	)		(1,171	)		(15,127	)		(9,264	)		(5,863	)
Income from discontinued operations		—			86			(86	)		—			86			(86	)

Net income (loss)	$	106,652		$	(20,479	)	$	127,131		$	305,744		$	183,603		$	122,141

The discussion under “Parent Company Results” below analyzes the results of operations of the Parent Company for the periods presented, and the discussion under “Segment Operating Results” below analyzes the results of operations related to our reportable segments.

Parent Company Results

The Parent Company currently has no separate operating activities apart from those conducted by ETP, Regency and their respective subsidiaries and the principal sources of cash flow are distributions it receives from its direct and indirect investments in the limited partner and general partner interests of ETP and Regency.

The following summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
Selling, general and administrative	$	(12,037	)	$	(15,079	)	$	3,042		$	(13,879	)	$	(17,415	)	$	3,536
Interest expense, net of interest capitalized		(40,587	)		(20,210	)		(20,377	)		(81,526	)		(36,916	)		(44,610	)
Equity in earnings of affiliates		120,626			75,362			45,264			267,268			221,740			45,528
Losses on non-hedged interest rate derivatives		—			(20,753	)		20,753			—			(35,177	)		35,177
Other, net		(1,653	)		(88	)		(1,565	)		(16,812	)		(212	)		(16,600	)

Selling, general and administrative. For the three and six months ended June 30, 2011 compared to the same period in the prior year, selling, general and administrative expense decreased primarily due to a decrease in acquisition-related costs. The three and six months ended June 30, 2011 reflected approximately $9.0 million in expenses incurred related to our pending acquisition of SUG (see “Recent Developments” above), while the three and six months ended June 30, 2010 reflect approximately $12.8 million in expenses incurred related to our acquisition of a controlling interest in Regency in May 2010.

Interest Expense. For the three and six months ended June 30, 2011 compared to the same period in the prior year, interest expense increased primarily due to the issuance of $1.8 billion aggregate principal amount of 7.5% senior notes in September 2010 the proceeds from which were used to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate interest rate swaps, and for general partnership purposes. In addition, interest expense for the periods presented reflected distributions on the ETE Preferred Units issued by ETE in connection with the acquisition of a controlling interest in Regency in May 2010. Distributions on ETE Preferred Units were $6.0 million and $12.0 million for the three and six months ended June 30, 2011, respectively, compared to $2.4 million reflected in the three and six months ended June 30, 2010.

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in ETP and Regency. The Parent Company recorded equity in earnings of ETP of $116.1 million and $75.8 million for the three months ended June 30, 2011 and 2010, respectively, and $259.8 million and $222.2 million for the six months ended June 30, 2011 and 2010, respectively. An analysis of ETP’s results is included in “Segment Operating Results” below. The three and six months ended June 30, 2011 also reflect the equity in earnings from Regency of $4.5 million and $7.5 million; whereas, the three and six months ended June 30, 2010 include equity in losses of Regency of $0.5 million, which represents only the period subsequent to the Parent Company’s acquisition of a controlling interest in Regency on May 26, 2010.

Losses on Non-Hedged Interest Rate Derivatives. The Parent Company terminated its interest rate swaps that were not accounted for as hedges in September 2010 in connection with the issuance of $1.8 billion of senior notes. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings. For the three and six months ended June 30, 2011, we recorded unrealized losses on our interest rate swaps as a result of decreases in the relevant floating index rates during the period.

Other, net. Other expenses increased between periods primarily due to non-cash charges recorded to increase the carrying value of the preferred units that were issued by the Parent Company in connection with the acquisition of a controlling interest in Regency in May 2010.

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. See further discussion of ETP and Regency’s operations in Note 1 to our consolidated financial statements.

We evaluate the performance of our operating segments based on net income. The following tables present the financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Net income (loss) by segment is as follows:


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
Investment in ETP	$	156,616		$	42,843		$	113,773		$	403,818		$	282,954		$	120,864
Investment in Regency		14,837			(4,895	)		19,732			29,142			(4,895	)		34,037
Corporate and Other		(56,413	)		(58,427	)		2,014			(118,828	)		(94,456	)		(24,372	)
Adjustments and Eliminations		(8,388	)		—			(8,388	)		(8,388	)		—			(8,388	)

Net income (loss)	$	106,652		$	(20,479	)	$	127,131		$	305,744		$	183,603		$	122,141

Investment in ETP


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
Revenues	$	1,628,095		$	1,267,706		$	360,389		$	3,315,672		$	3,139,687		$	175,985
Cost of products sold		1,008,628			770,857			237,771			2,003,085			1,995,722			7,363

Gross margin		619,467			496,849			122,618			1,312,587			1,143,965			168,622
Operating expenses		189,302			169,533			19,769			377,791			340,281			37,510
Depreciation and amortization		104,972			83,877			21,095			200,936			167,153			33,783
Selling, general and administrative		54,774			44,255			10,519			100,306			93,009			7,297

Operating income		270,419			199,184			71,235			633,554			543,522			90,032
Interest expense, net of interest capitalized		(116,466	)		(103,014	)		(13,452	)		(223,706	)		(207,976	)		(15,730	)
Equity in earnings of affiliates		5,040			4,072			968			6,673			10,253			(3,580	)
Gains (losses) on disposal of assets		(528	)		1,385			(1,913	)		(2,254	)		(479	)		(1,775	)
Gains on non-hedged interest rate derivatives		2,111			—			2,111			3,890			—			3,890
Impairment of investment in affiliate		—			(52,620	)		52,620			—			(52,620	)		52,620
Other, net		1,823			(1,595	)		3,418			2,041			747			1,294
Income tax expense		(5,783	)		(4,569	)		(1,214	)		(16,380	)		(10,493	)		(5,887	)

Net income	$	156,616		$	42,843		$	113,773		$	403,818		$	282,954		$	120,864

Gross Margin. For the three and six months ended June 30, 2011 compared to the three and six months ended June 30, 2010, ETP’s gross margin increased primarily due to the net impact of the following:

•

Revenues generated by ETP’s interstate transportation systems increased $34.8 million and $71.6 million, respectively, for the three and six months ended June 30, 2011 compared to the prior period primarily as a result of the Tiger pipeline being placed into service in December 2010. Increased revenue from the Tiger pipeline was partially offset by decreased revenue from the Transwestern pipeline.

•

Gross margin from ETP’s midstream business increased by $32.7 million and $38.6 million for the three and six months ended June 30, 2011, respectively. These increases were driven by higher volumes primarily from recent acquisitions and growth project, as well as the impacts of favorable NGL prices.

•

Gross margin from ETP’s NGL transportation and services business was $45.6 million for the three and six months ended June 30, 2011, which represented 100% of the results from Lone Star since it was acquired in May 2011. Accordingly, no comparative amounts were reflected in ETP’s results prior to May 2, 2011.

Operating Expenses. For the three and six months ended June 30, 2011 comparable period in the prior year, ETP’s operating expenses increased primarily due to operating expenses from ETP’s Tiger pipeline, which was placed into service in December and operating expenses of $6.3 million from Lone Star, which was acquired on May 2, 2011.

Depreciation and Amortization. ETP’s depreciation and amortization expense increased primarily due to incremental depreciation associated with ETP’s Tiger pipeline, which was placed in service in December 2010, and the continued expansion of ETP’s Louisiana and South Texas midstream assets.

Selling, General and Administrative. For the three and six months ended June 30, 2011, ETP’s selling, general and administrative expenses increased primarily due to increased employee-related costs, as well as additional selling, general and administrative costs related to Lone Star, which was acquired on May 2, 2011.

Interest Expense. Interest expense increased for the three and six months ended June 30, 2011 compared to the same periods in the prior year principally due to ETP’s issuance of $1.50 billion of senior notes in May 2011, the proceeds from which were used to repay borrowings on the ETP’s revolving credit facility (the “ETP Credit Facility”), to fund growth projects and for general partnership purposes. Interest expense was presented net of capitalized interest and allowance for debt funds used during construction, which totaled $3.4 million and $2.9 million for the three months ended June 30, 2011 and 2010, respectively, and $5.3 million and $3.9 million for the six months ended June 30, 2011 and 2010, respectively.

Equity in Earnings of Affiliates. ETP’s equity in earnings of affiliates decreased $3.6 million for the six months ended June 30, 2011 compared to the same period in the prior year primarily due to ETP’s transfer of substantially all of its interest in Midcontinent Express Pipeline, LLC (“MEP”) to ETE on May 26, 2010 in connection with the Regency Transactions. For the three and six months ended June 30, 2011, equity in earnings of affiliates primarily consisted of ETP’s proportionate share of the earnings of Fayetteville Express Pipeline LLC (“FEP”).

Gains on Non-Hedged Interest Rate Derivatives. Gains on non-hedged interest rate derivatives for the three and six months ended June 30, 2011 reflected swap settlements and amounts recognized on ETP’s outstanding swaps, which had a total notional amount of $1.10 billion as of June 30, 2011. No non-hedged interest rate swaps were outstanding during the same periods in the prior year.

Impairment of Investment in Affiliate. In conjunction with the transfer of its interest in MEP in May 2010, ETP recorded a non-cash charge of approximately $52.6 million during the three months ending June 30, 2010 to reduce the carrying value of its interest to its estimated fair value.

Income Tax Expense. The increase in ETP’s income tax expense between the periods was primarily due to increases in taxable income within ETP’s subsidiaries that are taxable corporations, and an increase in amounts recorded for the Texas margins tax resulting from increased operating income.

Investment in Regency


	Three Months Ended June 30,									Six Months Ended June 30,
	2011			2010			Change			2011			2010			Change
Revenues	$	356,498		$	96,980		$	259,518		$	673,750		$	96,980		$	576,770
Cost of products sold		259,475			70,174			189,301			475,736			70,174			405,562

Gross margin		97,023			26,806			70,217			198,014			26,806			171,208
Operating expenses		33,996			10,402			23,594			67,556			10,402			57,154
Depreciation and amortization		40,503			10,545			29,958			80,739			10,545			70,194
Selling, general and administrative		17,551			7,104			10,447			36,660			7,104			29,556
Losses on disposal of assets		153			10			143			181			10			171

Operating income (loss)		4,820			(1,255	)		6,075			12,878			(1,255	)		14,133
Interest expense, net of interest capitalized		(24,689	)		(8,081	)		(16,608	)		(44,696	)		(8,081	)		(36,615	)
Equity in earnings of affiliates		32,167			8,121			24,046			55,975			8,121			47,854
Other, net		2,641			(3,521	)		6,162			5,055			(3,521	)		8,576
Income tax expense		(102	)		(245	)		143			(70	)		(245	)		175
Income from discontinued operations		—			86			(86	)		—			86			(86	)

Net income (loss)	$	14,837		$	(4,895	)	$	19,732		$	29,142		$	(4,895	)	$	34,037

ETE obtained control of Regency on May 26, 2010. Changes between periods were due to the consolidation of Regency beginning May 26, 2010.

Regency adjusted its assets and liabilities to fair value as of May 26, 2010; therefore, the depreciation and amortization reflected above was based on Regency’s post-acquisition basis of assets.

Regency’s results include its equity in earnings related to its 49.9% interest in MEP subsequent to the Regency Transactions on May 26, 2010 and its 30% interest in Lone Star subsequent to ETP and Regency’s acquisition of Lone Star on May 2, 2011.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The principal sources of the Parent Company’s cash flow are its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The amount of cash that ETP and Regency distribute to their 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.

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 and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company 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.

On July 19, 2011, ETE entered into the Second Amended SUG Merger Agreement. Under the terms of the Second Amended SUG Merger Agreement, ETE would acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion, including $5.7 billion in cash and ETE common units and $3.7 billion of existing SUG indebtedness. Pursuant to the Second Amended SUG Merger Agreement, stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.

ETE intends to finance a portion of the cash component of the SUG Merger consideration with debt financing. Concurrently, and in connection with entering into the merger agreement, ETE entered into a debt commitment letter with the Credit Suisse Lenders, pursuant to which, subject to the conditions set forth therein, the Credit Suisse Lenders have committed to provide a 364-day Bridge Term Facility in an aggregate principal amount of $3.7 billion (or such lesser amount as is equal to the lesser of (i) the amount that is sufficient to fund the total amount of cash consideration paid in the SUG Merger and (ii) the amount that ETE may elect to borrow). The commitment is subject to various conditions, including (i) the absence of a material adverse effect on Southern Union having occurred subsequent to December 31, 2010, (ii) the Credit Suisse Lenders’ satisfaction that during the 60-day period after the date of the Commitment Letter, and subject to certain exceptions, there are no other issues of debt securities or commercial bank or other credit facilities by ETE, Southern Union or their respective wholly owned subsidiaries being announced, offered, placed or arranged, (iii) the execution of satisfactory definitive documentation and (iv) other customary closing conditions.

We expect ETP and Regency to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as it deems prudent to provide liquidity for new capital projects of its 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 ETP’s control.

ETP currently believes that its business has the following future capital requirements:

•

growth capital expenditures for its midstream and intrastate transportation and storage operations, primarily for construction of new pipelines and compression, for which ETP expects to spend between $450 million and $500 million for the remainder of 2011;

•

growth capital expenditures for its interstate transportation operations, excluding capital contributions to its joint ventures as discussed below, for the construction of new pipelines for which ETP expects to spend between $70 million and $90 million for the remainder of 2011;

•

growth capital expenditures for ETP’s NGL transportation and services operations of between $100 million and $150 million for the remainder of 2011;

•

growth capital expenditures for its retail propane operations of between $10 million and $20 million for the remainder of 2011; and

•

maintenance capital expenditures of between $60 million and $70 million for the remainder of 2011, 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; and (iv) capital expenditures for its propane operations to extend the useful lives of its existing propane assets in order to sustain its operations, including vehicle replacements on its propane vehicle fleet.

In addition to the capital expenditures noted above, ETP expects that capital contributions to its unconsolidated joint ventures that it currently has interests in will be between $190 million and $210 million for the remainder of 2011.

As discussed in Note 3 to our consolidated financial statements, we entered into the Amended Citrus Merger Agreement on July 18, 2011. ETP expects to fund substantially all of the cash portion of the purchase price ($1.895 billion) initially through the issuance of debt and borrowings from the ETP Credit Facility. ETP also intends to issue sufficient additional equity to maintain its investment grade credit rating and to use the proceeds from such equity issuances to repay other indebtedness and fund capital expenditures. In addition, ETP may enter into other acquisitions, including the potential acquisition of new pipeline systems and propane operations.

ETP generally funds its capital requirements with cash flows from operating activities and, to the extent that they exceed cash flows from operating activities, with proceeds of borrowings under existing credit facilities, long-term debt, the issuance of additional ETP Common Units or a combination thereof.

ETP raised $695.5 million in proceeds, net of commissions, from its Common Unit offering in April 2011 and $1.9 million in net proceeds from the issuance of 41,139 Common Units in connection with its distribution reinvestment plan (“DRIP”) in May 2011. In addition, ETP raised $72.9 million in net proceeds during the six months ended June 30, 2011 under ETP’s equity distribution program, as described in Note 11 to our consolidated financial statements. As of June 30, 2011, in addition to $130.9 million of cash on hand, ETP had available capacity under the ETP Credit Facility of $1.81 billion. Based on current estimates, ETP expects to utilize capacity under the ETP Credit Facility, along with cash from its operations, to fund its announced growth capital expenditures and working capital needs through the end of 2011; 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 its revolving credit facility (the “Regency Credit Facility”);

•

operating lease facilities;

•

asset sales;

•

debt offerings; and

•

issuance of additional partnership units.

As of June 30, 2011, in addition to approximately $3.1 million of cash on hand, Regency had available capacity under the Regency Credit Facility of approximately $559.0 million.

Regency expects its growth capital expenditures to be approximately $345 million in 2011, which includes approximately $168 million for its Gathering and Processing operations, mostly in South Texas, $95 million for its Contract Compression operations, $65 million for its Joint Ventures operations, $12 million for its Contract Treating operations, and $5 million for its Corporate and Others operations. In addition, Regency expects its maintenance capital expenditures to be approximately $17 million in 2011. 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.

For the six months ended June 30, 2011, Regency incurred $123.7 million of growth capital expenditures, which primarily related to $45.1 million for the fabrication of new compressor packages for its contract compression operations, $73.2 million for organic growth projects for its gathering and processing operations and $5.4 million for the fabrication of new treating plants for its contract treating operations. For the six months ended June 30, 2011, Regency incurred $5.4 million of maintenance capital expenditures.

Regency does not anticipate contributing any amounts to RIGS Haynesville Partnership Co. (“HPC”) in 2011 to fund HPC’s growth capital expenditures as these amounts are expected to be funded under HPC’s revolving credit facility.

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 ETP’s and Regency’s 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 unit-based 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.

Six months ended June 30, 2011 compared to six months ended June 30, 2010. Cash provided by operating activities during 2011 was $698.3 million as compared to $801.9 million for 2010. Net income was $305.7 million and $183.6 million for 2011 and 2010, respectively. The difference between net income and the net cash provided by operating activities consisted of non-cash items totaling $339.1 million and $253.9 million and changes in operating assets and liabilities of $21.2 million and $336.3 million for 2011 and 2010, respectively.

The non-cash activity in 2011 and 2010 consisted primarily of depreciation and amortization of $287.8 million and $184.4 million, respectively. In addition, non-cash compensation expense was $23.1 million and $15.8 million for 2011 and 2010, respectively.

Cash paid for interest, net of interest capitalized, was $349.3 million and $277.9 million for the six months ended June 30, 2011 and 2010, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, and cash contributions to ETP’s and Regency’s joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in ETP’s and Regency’s growth capital expenditures to fund their respective construction and expansion projects.

Six months ended June 30, 2011 compared to six months ended June 30, 2010. Cash used in investing activities during 2011 was $2.74 billion as compared to $786.2 million for 2010. In 2011, our subsidiaries paid cash for acquisitions of $1.95 billion, which primarily consisted of the acquisition of Lone Star and made advances to joint ventures of $22.7 million. In 2010, ETP paid cash for acquisitions of $153.4 million and we received $24.0 million in cash in the acquisition of Regency. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2011 were $794.2 million, including changes in accruals of $10.6 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2010 of $629.4 million, including changes in accruals of $39.3 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 ETP’s and Regency’s acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding at our subsidiaries.

Six months ended June 30, 2011 compared to six months ended June 30, 2010. Cash provided by financing activities during 2011 was $2.11 billion as compared to $0.2 million for 2010. In 2011, ETP received $770.2 million in net proceeds from offerings of ETP Common Units, including $72.9 million under ETP’s equity distribution program (see Note 11 to our consolidated financial statements), as compared to $574.5 million in 2010, which included $151.0 million under ETP’s equity distribution program. During 2011, we had a consolidated net increase in our debt level of $1.78 billion as compared to a net decrease of $96.2 million for 2010, primarily due to ETP’s issuance of $1.50 billion of principal amount of senior notes in May 2011 and Regency’s issuance of $500.0 million of principal amount senior notes in May 2011. We paid distributions of $246.0 million and $241.5 million to our partners in 2011 and in 2010. In addition, during 2011 and 2010, ETP paid distributions of $273.4 million and $230.6 million, respectively, on limited partner interests other than those held by the Parent Company. During 2011, Regency paid distributions of $103.0 million on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	June 30, 2011			December 31, 2010
Parent Company Indebtedness:
ETE Senior Notes	$	1,800,000		$	1,800,000
Subsidiary Indebtedness:
ETP Senior Notes		6,550,000			5,050,000
Regency Senior Notes		1,350,000			850,000
Transwestern Senior Unsecured Notes		870,000			870,000
HOLP Senior Secured Notes		90,400			103,127
ETP Revolving Credit Facility		143,968			402,327
Regency Revolving Credit Facility		330,000			285,000
Other long-term debt		8,367			9,671
Unamortized discounts, net		(10,371	)		(6,013	)
Fair value adjustments related to interest rate swaps		14,454			17,260

Total debt	$	11,146,818		$	9,381,372

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, 2010, filed with the SEC on February 28, 2011 and in Note 9 to our consolidated financial statements.

Revolving Credit Facilities

ETP Credit Facility. The ETP Credit Facility provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity). The ETP Credit Facility matures on July 20, 2012, unless ETP elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). Amounts borrowed under the ETP Credit Facility bear interest, at ETP’s option, at a Eurodollar rate plus an applicable margin or a base rate. The base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate or a federal funds effective rate plus 0.50%. The applicable margin for Eurodollar loans ranges from 0.30% to 0.70% based upon ETP’s credit rating and is currently 0.55% (0.60% if facility usage exceeds 50%). The commitment fee payable on the unused portion of the ETP Credit Facility varies based on ETP’s credit rating with a maximum fee of 0.125%. The fee is 0.11% based on ETP’s current rating.

As of June 30, 2011, ETP had a balance of $144.0 million outstanding under the ETP Credit Facility, and the amount available under the ETP Credit Facility was $1.81 billion, taking into account letters of credit of $42.9 million. The weighted average interest rate on the total amount outstanding at June 30, 2011 was 0.76%.

Regency Credit Facility. The Regency Credit Facility has aggregate revolving commitments of $900 million, with $100 million of availability for letters of credit. Regency also has the option to request an additional $250 million in revolving commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. The maturity date of the Regency Credit Facility is June 15, 2014.

The outstanding balance of revolving loans under the Regency Credit Facility bears interest at LIBOR plus a margin or an alternate base rate. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50% or an adjusted one-month LIBOR rate plus 1.00%. The applicable margin shall range from 1.50% to 2.25% for base rate loans, 2.50% to 3.25% for Eurodollar loans, and a commitment fee will range from 0.375% to 0.50%. Regency must also pay a participation fee for each revolving lender participating in letters of credit based upon the applicable margin and a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of the letter of credit exposure.

As of June 30, 2011, there was a balance outstanding under the Regency Credit Facility of $330.0 million in revolving credit loans and approximately $11.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of June 30, 2011, which is reduced by any letters of credit, was approximately $559.0 million. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 3.25%.

Senior Notes

ETP. In May 2011, ETP completed a public offering of $800 million aggregate principal amount of 4.65% Senior Notes due June 1, 2021 and $700 million aggregate principal amount of 6.05% Senior Notes due June 1, 2041. ETP used the proceeds, net of commissions, of approximately $1.48 billion to repay all of the borrowings outstanding under the ETP Credit Facility, to fund capital expenditures related to pipeline construction projects and for general partnership purposes.

ETP’s $6.55 billion of aggregate principal amount of ETP Senior Notes includes $600 million 9.7% ETP Senior Notes due March 15, 2019. The holders of those notes will have the right to require ETP to repurchase all or a portion of the notes on March 15, 2012 at a purchase price of equal to 100% of the principal amount (par value) of the notes tendered. The current market value of the notes is significantly in excess of the principal amount, making a repurchase at par value uneconomic by the holder. However, if such a repurchase were to occur, we would intend to refinance any amounts paid on a long-term basis.

Regency. In May 2011, Regency issued $500.0 million in senior notes that mature on July 15, 2021. The senior notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. Regency used the proceeds, net of commissions, of approximately $491.3 million to repay borrowings outstanding under the Regency Credit Facility. Regency capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the notes. Interest will be paid semi-annually and mature on July 15, 2021.

FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provided for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by Kinder Morgan Energy Partners, L.P. (“KMP”). Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate.

As of June 30, 2011, FEP had $968.5 million of outstanding borrowings under the FEP Facility. ETP’s contingent obligation with respect to its guaranteed portion of FEP’s outstanding borrowings was $484.3 million, which is not reflected on our consolidated balance sheets as of June 30, 2011. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 3.09%.

In July 2011, the FEP Facility was repaid with capital contributions from ETP and KMP totaling $390 million along with proceeds from a $600 million term loan credit facility maturing in July 2012 (which can be extended for one year at the option of FEP). Upon closing and funding of the term loan facility, the FEP facility was terminated. FEP also entered into a $50 million revolving credit facility maturing in July 2015. ETP does not guarantee FEP’s indebtedness under its term loan or new credit facility.

Covenants Related to Our Credit Agreements

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, 2010:


Quarter Ended	Record Date	Payment Date	Rate

December 31, 2010	February 7, 2011	February 18, 2011	$ 0.540
March 31, 2011	May 6, 2011	May 19, 2011	0.560
June 30, 2011	August 5, 2011	August 19, 2011	0.625

The total amounts of distributions declared and/or paid during the six months ended June 30, 2011 and 2010 were as follows (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):


	Six Months Ended June 30,
	2011		2010
Limited Partners	$	264,206	$	240,776
General Partner interest		821		748

Total ETE distributions	$	265,027	$	241,524

Cash Distributions Received from Subsidiaries

The total amount of distributions the Parent Company received or will receive from ETP and Regency relating to its limited partner interests, general partner interest and IDRs (shown in the period to which they relate) for the periods ended as noted below is as follows:


	Six Months Ended June 30,
	2011		2010
Distributions from ETP:
Limited Partners	$	89,780	$	100,750
General Partner interest		9,792		9,754
Incentive Distribution Rights		206,540		184,751

Total distributions from ETP		306,112		295,255

Distributions from Regency:
Limited Partners		23,509		11,689
General Partner interest		2,556		1,105
Incentive Distribution Rights		2,452		915

Total distributions from Regency		28,517		13,709

Total distributions received from subsidiaries	$	334,629	$	308,964

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, 2010:


Quarter Ended	Record Date	Payment Date	Rate

December 31, 2010	February 7, 2011	February 14, 2011	$ 0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375

The total amounts of ETP distributions declared and/or paid during the six months ended June 30, 2011 and 2010 were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):


	Six Months Ended June 30,
	2011		2010
Limited Partners:
Common Units	$	372,970	$	332,371
Class E Units		6,242		6,242

General Partner interest		9,792		9,754
Incentive Distribution Rights		206,540		184,751

Total ETP distributions	$	595,544	$	533,118

Cash Distributions Paid by Regency

Following are distributions declared and/or paid by Regency subsequent to December 31, 2010:


Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011		0.445
June 30, 2011	August 5, 2011	August 12, 2011		0.450

The total amounts of Regency distributions declared and/or paid during the six months ended June 30, 2011 and 2010 subsequent to our acquisition of Regency were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):


	Six Months Ended June 30,
	2011		2010
Limited Partners	$	131,523	$	53,229
General Partner interest		2,556		1,105
Incentive Distribution Rights		2,452		915

Total Regency distributions	$	136,531	$	55,249

CRITICAL ACCOUNTING POLICIES

Disclosure of our critical accounting policies is included in our Annual Report on Form 10-K for the year ended December 31, 2010.

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, 2010, 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, 2010. Since December 31, 2010, there have been no material changes to our primary market risk exposures or how those exposures are managed.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform 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 segment commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of June 30, 2011 and December 31, 2010.

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 our consolidated results of operations or other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of ETP’s and Regency’s 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.

Investment in ETP

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


	June 30, 2011								December 31, 2010
	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:
Basis Swaps IFERC/NYMEX		(26,145,000	)	$	3,625		$	93		(38,897,500	)	$	(2,334	)	$	304
Swing Swaps IFERC		(144,420,000	)		(2,782	)		30		(19,720,000	)		(2,086	)		2,228
Fixed Swaps/Futures		6,695,000			(10,360	)		3,394		(2,570,000	)		(11,488	)		1,176
Options — Calls		—			—			—		(3,000,000	)		62			7
Propane:
Forwards/Swaps		—			—			—		1,974,000			275			258

Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX		(26,040,000	)		(1,045	)		109		(28,050,000	)		722			322
Fixed Swaps/Futures		(38,285,000	)		11,002			18,283		(39,105,000	)		8,599			16,837

Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures		920,000			(50	)		413		(210,000	)		232			93
Options — Puts		15,180,000			6,860			4,967		26,760,000			10,545			7,125
Options — Calls		(15,180,000	)		3,545			515		(26,760,000	)		4,812			1,565
Propane:
Forwards/Swaps		14,700,000			276			2,181		32,466,000			6,589			4,196

Investment in Regency

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


	June 30, 2011							December 31, 2010
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures		3,670,000	$	1,371		$	1,724		3,830,000	$	2,053		$	1,684
Propane:
Forwards/Swaps		18,564,000		(6,157	)		2,641		18,648,000		(4,203	)		2,277
NGLs:
Forwards/Swaps		1,006,000		(10,484	)		5,003		1,212,110		(6,288	)		4,910
WTI Crude:
Forwards/Swaps		483,000		(3,651	)		4,789		373,655		(3,581	)		3,501

Interest Rate Risk

As of June 30, 2011, ETP had $144.0 million of variable rate debt outstanding under its revolving credit facilities and Regency had $330.0 million of variable rate debt outstanding under its revolving credit facilities. ETE had no variable rate debt outstanding as of June 30, 2011. A hypothetical change of 100 basis points would result in a change to interest

expense of $4.7 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 variable interest rates that is not hedged, our results of operations, cash flows and financial condition could be adversely affected by increases in interest rates. The following interest rate swaps were outstanding as of June 30, 2011 and December 31, 2010 (dollars in thousands), none of which are designated as hedges for accounting purposes:

Notional Amount
Outstanding

Entity

Term

Type⁽¹⁾

June 30,
2011

December 31,
2010

ETP

August 2012⁽²⁾

Forward starting to pay a fixed rate of 3.64% and receive a floating rate

400,000

ETP

July 2013⁽³⁾

Forward starting to pay a fixed rate of 4.13% and receive a floating rate

200,000

—

ETP

July 2018

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

500,000

Regency

April 2012

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

250,000

⁽¹⁾	Floating rates are based on LIBOR.

⁽²⁾	These forward starting swaps have an effective date of August 2012 and a term of 10 years; however, the swaps have a mandatory termination provision and will be settled in August 2012.

⁽³⁾	These forward starting swaps have an effective date of July 2013 and a term of 10 years; however, the swaps have a mandatory termination provision and will be settled in July 2013.

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 of approximately $21.2 million as of June 30, 2011 and $1.3 million as of December 31, 2010. For ETP’s $500.0 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 of $5.0 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

ETP’s counterparties consist primarily of petrochemical companies and other industrial, mid-size to major oil and gas companies and power companies. This concentration of counterparties may impact its 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 financial position or results of operations as a result of counterparty performance.

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 Securities Exchange Act of 1934 (“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the President (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of June 30, 2011 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

Effective January 1, 2011, we began to integrate certain of Regency’s business functions under a shared services agreement with ETE Services Company, LLC. In connection with this integration, certain of Regency’s controls and procedures have been changed to conform to the existing controls of our other subsidiaries. During the three months ended June 30, 2011, Regency’s accounting systems were transitioned to the accounting systems of the Parent Company and its other subsidiaries and accordingly certain related controls of Regency were changed at that time. None of these changes were in response to an identified deficiency or weakness in Regency’s internal control over financial reporting.

The acquisition of LDH (the “LDH Acquisition”) was closed on May 2, 2011 and the evaluation of the internal control structure of LDH has begun. We expect the evaluation to continue during the remainder of 2011. In recording the LDH Acquisition, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of Lone Star that were included in our earnings for the three months ended June 30, 2011.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended June 30, 2011 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, 2010 and Note 14 — 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 June 30, 2011.

ITEM 1A. RISK FACTORS

Our recently announced proposed merger with Southern Union Company (the “SUG Merger”) presents several risks. Many of those risks are similar to the risks associated with our existing business, as we have previously 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 of our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

Risks Related to the SUG Merger

The failure to successfully combine the businesses of ETE and Southern Union in the expected time frame may adversely affect ETE’s future results.

The success of the SUG Merger will depend, in part, on the ability of ETE to realize the anticipated benefits from combining the businesses of ETE and Southern Union. To realize these anticipated benefits, ETE’s and Southern Union’s businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the SUG 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 SUG Merger.

ETE and Southern Union, including their respective subsidiaries, have operated and, until the completion of the SUG 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 ETE’s ability to maintain relationships with customers and employees after the SUG Merger or to achieve the anticipated benefits of the SUG 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 ETE and Southern Union.

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

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

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

The pendency of the SUG Merger could materially adversely affect the future business and operations of ETE or Southern Union or result in a loss of Southern Union employees.

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

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

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

•

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

•

ETE would not realize the expected benefits of the SUG Merger;

•

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

•

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

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

The completion of the SUG Merger will require ETE to enter into a new financing arrangement. If ETE’s financing for the SUG Merger becomes unavailable, the SUG Merger may not be completed.

In the event that the financing contemplated by the debt commitment letter is not available to ETE, other financing may not be available to ETE on acceptable terms, in a timely manner, or at all. If other financing becomes necessary and ETE is unable to secure such additional financing, the SUG Merger may not be completed. ETE does not have a right to terminate the merger agreement in the event it does not have adequate funds to complete the transaction at closing. In the merger agreement, ETE represented to Southern Union that it would have available, at the closing of the SUG Merger, all funds required to consummate the transactions contemplated by the merger agreement. Southern Union would have a right to terminate the merger agreement if ETE breached this representation in a manner such that ETE would not be able to satisfy this representation on or before June 30, 2012, or in the event some regulatory approvals have not been achieved, December 31, 2012.

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

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

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

In certain circumstances, upon termination of the merger agreement, Southern Union would be responsible for reimbursing ETE for up to $54.0 million in expenses related to the transaction and may be obligated to pay a breakup fee to ETE of $181.3 million. If the merger agreement is terminated, the expense reimbursements and the breakup fee required to be paid by Southern Union under the merger agreement may require Southern Union to seek loans or borrow amounts to enable it to pay these amounts to ETE. In either case, Southern Union may not be able to fulfill such obligations.

Southern Union will be a corporate subsidiary of ETE after the SUG Merger and will remain subject to corporate-level income taxes.

After the SUG Merger, ETE will own and operate certain aspects of Southern Union’s business through Southern Union as a wholly owned corporate subsidiary of ETE. Accordingly, Southern Union will continue to be subject to corporate-level tax, which may reduce the cash available for distribution to ETE and, in turn, to ETE unitholders. If the IRS were to successfully assert that Southern Union has more tax liability than ETE anticipated or legislation were enacted that increased the corporate tax rate, the cash available for distribution by ETE 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 5. OTHER INFORMATION

None.

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/A) (5/13/10)	2.1	General Partner Purchase Agreement, dated May 10, 2010, by and among Regency GP Acquirer, L.P., Energy Transfer Equity, L.P. and ETE GP Acquirer LLC.

2.2	1-32740 (8-K/A) (5/13/10)	2.2	Redemption and Exchange Agreement, dated May 10, 2010, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P.

2.3	1-32740 (8-K/A) (5/13/10)	2.3	Contribution Agreement, dated May 10, 2010, by and among Energy Transfer Equity, L.P., Regency Energy Partners LP and Regency Midcontinent Express LLC.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit

2.4	001-32740 (425) (6/17/11)	2.1	Agreement and Plan of Merger, by and among, Energy Transfer Equity, L.P., Sigma Acquisition Corporation, and Southern Union Company, dated as of June 15, 2011.

3.1	333-128097 (S-1) (9/2/05)	3.1	Certificate of Conversion of Energy Transfer Company, L.P.

3.2	333-128097 (S-1) (9/2/05)	3.2	Certificate of Limited Partnership of Energy Transfer Equity, L.P.

3.3	1-32740 (8-K) (2/14/06)	3.1	Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.3.1	1-32740 (10-K) (8/31/06)	3.3.1	Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.3.2	1-32740 (8-K) (11/13/07)	3.3.2	Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.3.3	1-32740 (8-K) (6/2/10)	3.1	Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.4	333-128097 (S-1) (9/2/05)	3.4	Certificate of Conversion of LE GP, LLC.

3.5	333-128097 (S-1) (9/2/05)	3.5	Certificate of Formation of LE GP, LLC.

3.6	1-32740 (8-K) (5/8/07)	3.6.1	Amended and Restated Limited Liability Company Agreement of LE GP, LLC.

3.6.1	1-32740 (8-K) (12/23/09)	3.1	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of LE GP, LLC.

3.7	1-11727 (8-K) (7/28/09)	3.1	Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.8	333-04018 (S-1/A) (6/21/96)	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.1	1-11727 (10-K) (8/31/00)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.2	1-11727 (10-Q) (5/31/02)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.3	1-11727 (10-Q) (2/29/04)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.9	1-11727 (10-Q) (2/29/04)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.

3.10	1-11727 (10-Q) (2/28/02)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.

3.11	1-11727 (10-Q) (5/31/07)	3.5	Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P.

3.12	1-11727 (10-Q) (5/31/07)	3.6	Third Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit

3.12.1	1-11727 (8-K) (8/10/10)	3.6	Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C.

3.13	333-128097 (S-1/A) (12/20/05)	3.13	Certificate of Formation of Energy Transfer Partners, L.L.C.

3.13.1	333-128097 (S-1/A) (12/20/05)	3.13.1	Certificate of Amendment of Energy Transfer Partners, L.L.C.

3.14	333-128097 (S-1/A) (12/20/05)	3.14	Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P.

3.15	1-32740 (8-K) (8/10/10)	3.2	Second Amendment to Amended and Restated Limited Liability Company Agreement of Regency GP, L.L.C

4.1	1-32740 (8-K) (6/2/10)	4.1	Registration Rights Agreement by and among Energy Transfer Equity, L.P. and Regency GP Acquirer, L.P., dated as of May 26, 2010.

4.2	1-32740 (8-K) (9/20/10)	4.1	Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee.

4.3	1-32740 (8-K) (9/20/10)	4.2	First Supplemental Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes).

10.1	1-32740 (8-K) (9/20/10)	10.1	Credit Agreement dated as of September 20, 2010 among Energy Transfer Equity, L.P., Credit Suisse AG, as administrative agent and collateral agent, the other lenders party thereto and Credit Suisse Securities (USA) LLC, as sole lead arranger and sole bookrunner.

10.1.1			Amendment No. 1 to Credit Agreement among Energy Transfer Equity, L.P., Credit Suisse AG, as administrative agent and collateral agent, the other lenders party thereto and Credit Suisse Securities (USA) LLC, as sole lead arranger and sole bookrunner.

10.2	1-32740 (8-K) (9/20/10)	10.2	Pledge and Security Agreement dated September 20, 2010 among Energy Transfer Equity, L.P., the other grantors named therein and Credit Suisse AG, Cayman Islands Branch, as collateral agent.

10.3	1-32740 (425)(6/17/11)	10.1	Consulting Agreement dated June 15, 2011, by and among Southern Union, a Delaware corporation, Energy Transfer Equity, L.P., and George L. Lindemann.

10.4	1-32740 (425)(6/17/11)	10.2	Consulting Agreement dated June 15, 2011, by and among Southern Union, a Delaware corporation, Energy Transfer Equity, L.P., and Eric D. Herschmann.

10.5	1-32740 (425)(6/17/11)	10.3	Non-Competition, Non-Solicitation and Confidentiality Agreement dated June 15, 2011, by and between George L. Lindemann, Southern Union Company, a Delaware corporation and Energy Transfer Equity, L.P.

10.6	1-32740 (425)(6/17/11)	10.4	Non-Competition, Non-Solicitation and Confidentiality Agreement dated June 15, 2011, by and between Eric D. Herschmann, Southern Union Company, a Delaware corporation and Energy Transfer Equity, L.P.

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.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit

99.1			Statement of Policies Relating to Potential Conflicts Among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP, dated as of April 26, 2011.

101			Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010; (ii) our Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010; (iii) our Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2011 and 2010; (iv) our Consolidated Statement of Equity for the six months ended June 30, 2011; (v) our Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010; and (vi) the notes to our Consolidated Financial Statements.

*	Incorporated herein by reference.

SIGNATURE

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


	ENERGY TRANSFER EQUITY, L.P.

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

Date: August 8, 2011	By:	/s/ John W. McReynolds
		John W. McReynolds
		President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)

Amendment No. 1 to Credit Agreement

Exhibit 10.1.1

AMENDMENT NO. 1 TO CREDIT AGREEMENT

THIS AMENDMENT NO. 1 TO CREDIT AGREEMENT (this “Amendment”) dated as of November 11, 2010, is among Energy Transfer Equity, L.P., a Delaware limited partnership (the “Borrower”), the several banks and other financial institutions signatories hereto, and Credit Suisse AG, as Administrative Agent for the Lenders (the “Administrative Agent”).

RECITALS

A. The Borrower, the Lenders and the Administrative Agent are parties to a Credit Agreement dated as of September 20, 2010 (as amended, modified or supplemented prior to the date hereof, the “Credit Agreement”).

B. The Borrower has requested that the Credit Agreement be amended in order to exclude from the calculation of the financial covenants in the Credit Agreement the effect of various charges incurred by the Borrower in connection with the prepayment its previous credit agreement and the termination of related interest rate protection agreements.

NOW, THEREFORE, in consideration of the foregoing and the mutual covenants set forth in this Amendment, the Borrower and the Majority Lenders agree as follows:

1. Defined Terms. Unless otherwise defined in this Amendment, capitalized terms used in this Amendment have the meanings assigned to those terms in the Credit Agreement.

2. Amendments to Credit Agreement. The Credit Agreement is hereby amended as follows:

(a) Clause (c) of the definition of “Consolidated EBITDA of the Borrower” in Section 1.01 of the Credit Agreement is hereby amended to read as follows:

(c) Consolidated Net Income of the Borrower and its Restricted Subsidiaries for such four Fiscal Quarter period, plus (i) each of the following to the extent deducted in determining such Consolidated Net Income (A) all Consolidated Interest Expense, (B) all income taxes (including any franchise taxes to the extent based upon net income), (C) all depreciation and amortization (including amortization of good will and debt issue costs), (D) Prepayment Hedge Termination Expenses to the extent not included in Consolidated Interest Expense, and (E) any other non-cash charges or losses, minus (ii) each of the following (A) all non-cash items of income or gain which were included in determining such Consolidated Net Income, and (B) any cash payments made during such period in respect of items described in clause (i)(E) of this clause (c) subsequent to the Fiscal Quarter in which the relevant non-cash charges or losses were reflected as a charge in the statement of Consolidated Net Income; provided that the determinations in this clause (c) shall be made excluding each MLP and its subsidiaries. For the avoidance of doubt, the determinations in this clause (c) shall not include Consolidated Net Income attributable to distributions by an MLP.

(b) The definition of “Consolidated Fixed Charges” in Section 1.01 of the Credit Agreement is hereby amended to read as follows and the definition of Prepayment Hedge Termination Expenses is added:

“Consolidated Fixed Charges” means, for any period, without duplication, the sum of (i) the preferred distributions paid in cash during such period on the Restructuring Preferred Units plus (ii) Consolidated Interest Expense for such period; provided that the determinations in this definition shall be made excluding any cash payments made to terminate any Hedging Contract in connection with the repayment of the Existing Credit Agreement (the “Prepayment Hedge Termination Expenses”).

“Prepayment Hedge Termination Expenses” has the meaning given to such term in the definition of Consolidated Fixed Charges.

3. Conditions to Effectiveness. This Amendment will become effective on the date on which the Administrative Agent shall have received this Amendment, executed and delivered by the Borrower, the Guarantors, the Administrative Agent and the Majority Lenders.

4. Representations and Warranties. The Borrower hereby represents and warrants to the Administrative Agent and each of the Lenders as follows:

(a) This Amendment has been duly authorized by all necessary corporate action and constitutes the binding obligation of the Borrower.

(b) Each of the representations and warranties made by the Borrower and the Guarantors in or pursuant to the Credit Agreement and the other Loan Documents is true and correct in all material respects as of the date hereof, as if made (after giving effect to this Amendment) on and as of such date, except for any representations and warranties made as of a specified date, which were true and correct in all material respects as of such specified date.

(c) After giving effect to this Amendment, no Default or Event of Default has occurred and is continuing as of the date of this Amendment.

(d) Since December 31, 2009, no Material Adverse Effect has occurred.

5. Continuing Effect of the Credit Agreement. This Amendment does not constitute a waiver of any provision of the Credit Agreement and is not to be construed as a consent to any action on the part of the Borrower that would require a waiver or consent of the Lenders or an amendment or modification to any term of the Loan Documents. The Borrower hereby confirms and ratifies the Credit Agreement as amended hereby and each of the other Loan Documents to which it is a party and acknowledges and agrees that the same continue in full force and effect as amended hereby (as applicable).

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6. Reference to the Credit Agreement. Upon the effectiveness of this Amendment, each reference in the Credit Agreement to “this Agreement,” “hereunder,” “herein” or words of like import refer to the Credit Agreement, as amended by this Amendment.

7. Designation as Loan Document. This Amendment is a Loan Document.

8. Counterparts. This Amendment may be executed by all parties hereto in any number of separate counterparts each of which may be delivered in original, facsimile or other electronic (e.g., “.pdf”) form and all of such counterparts taken together constitute one instrument.

9. References. The words “hereby,” “herein,” “hereinabove,” “hereinafter,” “hereinbelow,” “hereof,” “hereunder” and words of similar import when used in this Amendment refer to this Amendment as a whole and not to any particular article, section or provision of this Amendment. References in this Amendment to a section number are to such sections of the Credit Agreement unless otherwise specified.

10. Headings Descriptive. The headings of the several sections of this Amendment are inserted for convenience only and do not in any way affect the meaning or construction of any provision of this Amendment.

11. Governing Law. This Amendment is governed by and will be construed in accordance with the law of the State of New York.

12. Payment of Expenses. The Borrower shall pay or reimburse the Administrative Agent for all of its out-of-pocket costs and reasonable expenses incurred in connection with this Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

13. Final Agreement of the Parties. THIS AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[Signature Pages Follow]

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IN WITNESS WHEREOF, the parties are signing this Amendment as of the date first above written.


ENERGY TRANSFER EQUITY, L.P.

By: LE GP, LLC, its general partner

By:		/s/ John W. McReynolds
Name:		John W. McReynolds
Title:		President and Chief Financial Officer