Edgar Filing: Energy Transfer Equity, L.P.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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 March 31, 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 May 2, 2011, the registrant had units outstanding as follows:

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

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries


PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Condensed Consolidated Balance Sheets – March 31, 2011 and December 31, 2010			1

Condensed Consolidated Statements of Operations – Three Months Ended March 31, 2011 and 2010			3

Condensed Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2011 and 2010			4

Condensed Consolidated Statement of Equity – Three Months Ended March 31, 2011			5

Condensed Consolidated Statements of Cash Flows – Three Months Ended March 31, 2011 and 2010			6

Notes to Condensed Consolidated Financial Statements			7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			37

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			49

ITEM 4. CONTROLS AND PROCEDURES			52

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS			52

ITEM 1A. RISK FACTORS			52

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			54

ITEM 3. DEFAULTS UPON SENIOR SECURITIES			54

ITEM 4. [RESERVED]

ITEM 5. OTHER INFORMATION			54

ITEM 6. EXHIBITS			54

SIGNATURE			57

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 in the energy industry and throughout this document:


/d		per day

Bbls		barrels

Btu		British thermal unit, an energy measurement

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

Dth		million British thermal units (“dekatherm”). A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)


	March 31, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	143,032		$	86,264
Marketable securities		2,640			2,032
Accounts receivable, net of allowance for doubtful accounts of $6,833 and $6,706 as of March 31, 2011 and December 31, 2010, respectively		591,990			612,357
Accounts receivable from related companies		89,129			76,331
Inventories		300,522			366,384
Exchanges receivable		19,363			21,926
Price risk management assets		14,338			16,357
Other current assets		151,019			109,359

Total current assets		1,312,033			1,291,010

PROPERTY, PLANT AND EQUIPMENT		13,543,244			13,284,430
ACCUMULATED DEPRECIATION		(1,554,656	)		(1,431,698	)

		11,988,588			11,852,732

ADVANCES TO AND INVESTMENTS IN AFFILIATES		1,352,577			1,359,979
LONG-TERM PRICE RISK MANAGEMENT ASSETS		16,256			13,971
GOODWILL		1,600,611			1,600,611
INTANGIBLES AND OTHER ASSETS, net		1,240,097			1,260,427

Total assets	$	17,510,162		$	17,378,730

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)


	March 31, 2011			December 31, 2010
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	369,198		$	421,556
Accounts payable to related companies		20,013			27,351
Exchanges payable		20,557			16,003
Price risk management liabilities		23,190			13,172
Accrued and other current liabilities		545,469			567,688
Current maturities of long-term debt		35,120			35,305

Total current liabilities		1,013,547			1,081,075

LONG-TERM DEBT, less current maturities		9,570,199			9,346,067
SERIES A CONVERTIBLE PREFERRED UNITS (Note 10)		332,640			317,600
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		83,031			79,465
OTHER NON-CURRENT LIABILITIES		249,462			235,848

COMMITMENTS AND CONTINGENCIES (Note 14)

PREFERRED UNITS OF SUBSIDIARY (Note 10)		70,991			70,943

EQUITY:
PARTNERS’ CAPITAL:
General Partner		440			520
Limited Partners:
Common Unitholders (222,972,708 and 222,941,172 units authorized, issued and outstanding at March 31, 2011 and December 31, 2010, respectively)		89,860			115,350
Accumulated other comprehensive (loss) income		(782	)		4,798

Total partners’ capital		89,518			120,668
Noncontrolling interest		6,100,774			6,127,064

Total equity		6,190,292			6,247,732

Total liabilities and equity	$	17,510,162		$	17,378,730

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)


	Three Months Ended March 31,
	2011			2010
REVENUES:
Natural gas operations	$	1,428,957		$	1,306,709
Retail propane		528,466			533,439
Other		31,697			31,833

Total revenues		1,989,120			1,871,981

COSTS AND EXPENSES:
Cost of products sold — natural gas operations		883,769			912,606
Cost of products sold — retail propane		310,864			304,981
Cost of products sold — other		6,793			7,278
Operating expenses		220,696			170,748
Depreciation and amortization		139,256			86,331
Selling, general and administrative		63,499			51,109

Total costs and expenses		1,624,877			1,533,053

OPERATING INCOME		364,243			338,928

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(167,929	)		(121,671	)
Equity in earnings of affiliates		25,441			6,181
Losses on disposal of assets		(1,754	)		(1,864	)
Gains (losses) on non-hedged interest rate derivatives		1,520			(14,424	)
Other, net		(12,526	)		2,143

INCOME BEFORE INCOME TAX EXPENSE		208,995			209,293
Income tax expense		9,903			5,211

NET INCOME		199,092			204,082

Less: Net income attributable to noncontrolling interest		110,452			91,305


NET INCOME ATTRIBUTABLE TO PARTNERS		88,640			112,777

GENERAL PARTNER’S INTEREST IN NET INCOME		274			349


LIMITED PARTNERS’ INTEREST IN NET INCOME	$	88,366		$	112,428


BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.40		$	0.50


BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,954,674			222,941,108


DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.40		$	0.50


DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,954,674			222,941,108

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)


	Three Months Ended March 31,
	2011			2010
Net income	$	199,092		$	204,082

Other comprehensive (loss) income, net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		(13,539	)		830
Change in value of derivative instruments accounted for as cash flow hedges		(10,838	)		23,803
Change in value of available-for-sale securities		608			(2,329	)

		(23,769	)		22,304

Comprehensive income		175,323			226,386
Less: Comprehensive income attributable to noncontrolling interest		92,263			108,128

Comprehensive income attributable to partners	$	83,060		$	118,258

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 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		(374	)		(120,389	)		—			—			(120,763	)
Subsidiary distributions		—			—			—			(179,631	)		(179,631	)
Subsidiary units issued for cash		22			7,150			—			50,201			57,373
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings		—			275			—			10,572			10,847
Non-cash executive compensation		—			6			—			306			312
Other, net		(2	)		(898	)		—			(1	)		(901	)
Other comprehensive loss, net of tax		—			—			(5,580	)		(18,189	)		(23,769	)
Net income		274			88,366			—			110,452			199,092

Balance, March 31, 2011	$	440		$	89,860		$	(782	)	$	6,100,774		$	6,190,292

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)


	Three Months Ended March 31,
	2011			2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	358,149		$	475,040

CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid for acquisitions		(3,060	)		(149,619	)
Capital expenditures (excluding allowance for equity funds used during construction)		(279,587	)		(119,721	)
Contributions in aid of construction costs		2,754			2,174
Advances to affiliates, net		(11,053	)		(50	)
Proceeds from the sale of assets		687			1,074

Net cash used in investing activities		(290,259	)		(266,142	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		997,094			89,388
Principal payments on debt		(763,615	)		(251,521	)
Subsidiary equity offering, net of issue costs		57,373			504,480
Distributions to partners		(120,763	)		(120,762	)
Distributions to noncontrolling interests		(179,631	)		(114,369	)
Other		(1,580	)		—

Net cash (used in) provided by financing activities		(11,122	)		107,216

INCREASE IN CASH AND CASH EQUIVALENTS		56,768			316,114
CASH AND CASH EQUIVALENTS, beginning of period		86,264			68,315

CASH AND CASH EQUIVALENTS, end of period	$	143,032		$	384,429

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED 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 March 31, 2011, our equity interests consisted of:


	General Partner Interest (as a % of total partnership interest)			Incentive Distribution Rights (“IDRs”)			Common Units
ETP		1.8	%		100	%		50,226,967
Regency		2.0	%		100	%		26,266,791

The unaudited condensed consolidated financial statements of ETE presented herein for the three month periods ended March 31, 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 months ended March 31, 2010 do not include the results of Regency.

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 more than 17,500 miles of gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas. ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.

•

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.

Preparation of Interim Financial Statements

The accompanying condensed consolidated balance sheets as of December 31, 2010, which have been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of the Partnership, as of March 31, 2011 and for the three months ended March 31, 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 March 31, 2011, and the Partnership’s results of operations and cash flows for the three months ended March 31, 2011 and 2010. The unaudited interim condensed 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 the midstream and intrastate transportation and storage 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.	ACQUISITIONS:

LDH Acquisition

On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by the ETP and 30% by Regency, acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), a wholly owned subsidiary of Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”), from Louis Dreyfus for approximately $1.97 billion in cash. 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 $591.6 million to fund its 30% share of the purchase price.

LDH owns and operates a natural gas liquids storage, fractionation and transportation business. LDH’s storage assets are primarily located in Mont Belvieu, Texas, one of the largest NGL storage, distribution and trading complexes in North America. Its West Texas Pipeline transports NGLs through a 1,066-mile 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. LDH also owns and operates fractionation and processing assets located in Louisiana. The acquisition of LDH is expected to significantly expand the Partnership’s asset portfolio, adding an NGL platform with storage, transportation and fractionation capabilities. Additionally, this acquisition will provide additional consistent fee-based revenues.

At the time our condensed consolidated financial statements were issued, the initial accounting for this business combination was incomplete; therefore, supplemental pro forma information was not yet available and is not included herein.

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.

Net cash provided by operating activities is comprised of the following:


	Three Months Ended March 31,
	2011			2010
Net income	$	199,092		$	204,082

Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		139,256			86,331
Amortization of finance costs charged to interest		5,080			2,990
Non-cash unit-based compensation expense		11,073			7,424
Non-cash executive compensation expense		312			312
Losses on disposal of assets		1,754			1,864
Distributions in excess of equity in earnings of affiliates, net		21,582			10,109
Other non-cash		17,670			193
Changes in operating assets and liabilities, net of effects of acquisitions		(37,670	)		161,735

Net cash provided by operating activities	$	358,149		$	475,040

Non-cash investing and financing activities are as follows:


	Three Months Ended March 31,
	2011		2010
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	107,451	$	68,436

Gain from subsidiary issuances of common units to noncontrolling interests (recorded in partners’ capital)	$	7,172	$	62,425

5.	INVENTORIES:

Inventories consisted of the following:


	March 31, 2011		December 31, 2010
Natural gas and NGLs, excluding propane	$	119,975	$	170,179
Propane		52,653		76,341
Appliances, parts and fittings and other		127,894		119,864

Total inventories	$	300,522	$	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 condensed consolidated balance sheets and in cost of products sold in our condensed consolidated statements of operations.

6.	INTANGIBLES AND OTHER ASSETS:

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


	March 31, 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)	$	970,441	$	(97,959	)	$	971,657	$	(88,583	)
Trade names (20 years)		65,500		(2,729	)		65,500		(1,910	)
Noncompete agreements (3 to 15 years)		20,814		(12,180	)		21,165		(11,888	)
Patents (9 years)		750		(139	)		750		(118	)
Other (10 to 15 years)		1,320		(518	)		1,320		(492	)

Total amortizable intangible assets		1,058,825		(113,525	)		1,060,392		(102,991	)
Non-amortizable intangible assets — Trademarks		77,655		—			77,445		—

Total intangible assets		1,136,480		(113,525	)		1,137,837		(102,991	)
Other assets:
Financing costs (3 to 30 years)		135,867		(42,894	)		137,012		(38,945	)
Regulatory assets		107,245		(15,413	)		107,384		(14,445	)
Other		32,878		(541	)		35,001		(426	)

Total intangibles and other assets	$	1,412,470	$	(172,373	)	$	1,417,234	$	(156,807	)

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


	Three Months Ended March 31,
	2011		2010
Reported in depreciation and amortization	$	13,141	$	5,146

Reported in interest expense	$	4,572	$	2,917

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 March 31, 2011 was $10.55 billion and $9.61 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 condensed 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 March 31, 2011 and December 31, 2010 based on inputs used to derive their fair values:


	Fair Value Measurements at March 31, 2011 Using
	Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets:
Marketable securities	$	2,640		$	2,640		$	—		$	—
Interest rate derivatives		27,580			—			27,580			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		65,357			65,357			—			—
Swing Swaps IFERC		7,358			1,228			6,130			—
Fixed Swaps/Futures		10,843			9,284			1,559			—
Options — Puts		20,293			—			20,293			—
Propane — Forward Swaps		1,395			—			1,395			—

Total commodity derivatives		105,246			75,869			29,377			—

Total Assets	$	135,466		$	78,509		$	56,957		$	—


Liabilities:
Interest rate derivatives	$	(26,350	)	$	—		$	(26,350	)	$	—
Preferred Units		(332,640	)		—			—			(332,640	)
Embedded derivatives in the Regency Preferred Units		(54,448	)		—			—			(54,448	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		(55,433	)		(55,433	)		—			—
Swing Swaps IFERC		(6,313	)		(2,299	)		(4,014	)		—
Fixed Swaps/Futures		(18,493	)		(18,331	)		(162	)		—
Options — Calls		(1,665	)		—			(1,665	)		—
NGLs — Forward Swaps		(17,721	)		—			(17,721	)		—
WTI Crude Oil		(7,542	)		—			(7,542	)		—

Total commodity derivatives		(107,167	)		(76,063	)		(31,104	)		—

Total Liabilities	$	(520,605	)	$	(76,063	)	$	(57,454	)	$	(387,088	)


	Fair Value Measurements at December 31, 2010 Using
	Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Observable Inputs (Level 2)			Significant Unobservable Inputs (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 — Puts		26,241			—			26,241			—
NGLs — Forward Swaps		192			—			192			—
Propane — Forward Swaps		6,864			—			6,864			—

Total commodity derivatives		95,690			59,792			35,898			—

Total Assets	$	118,512		$	61,824		$	56,688		$	—


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	)		—
NGLs — Forward Swaps		(10,684	)		—			(10,684	)		—
WTI Crude Oil		(3,581	)		—			(3,581	)		—

Total commodity derivatives		(80,300	)		(62,717	)		(17,583	)		—

Total Liabilities	$	(475,845	)	$	(62,717	)	$	(38,505	)	$	(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 three months ended March 31, 2011. There were no transfers between the fair value hierarchy levels for the three months ended March 31, 2011.


Balance, December 31, 2010	$	(374,623	)
Net unrealized losses included in other income (expense)		(12,465	)

Balance, March 31, 2011	$	(387,088	)

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 March 31,
	2011			2010
Basic Net Income per Limited Partner Unit:

Limited Partners’ interest in net income	$	88,366		$	112,428


Weighted average Limited Partner units		222,954,674			222,941,108


Basic net income per Limited Partner unit	$	0.40		$	0.50


Diluted Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	88,366		$	112,428
Dilutive effect of equity-based compensation of subsidiaries		(204	)		(173	)

Diluted net income available to Limited Partners	$	88,162		$	112,255


Weighted average Limited Partner units		222,954,674			222,941,108


Diluted net income per Limited Partner unit	$	0.40		$	0.50

The calculation above for the three months ended March 31, 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:

Revolving Credit Facilities

ETE Senior Secured Revolving Credit Facilities

The Parent Company has a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. As of March 31, 2011, there were no outstanding borrowings under the Parent Company Credit Agreement.

Under the Parent Company Credit Agreement, the obligations of ETE are secured by all tangible and intangible assets of ETE and certain of its subsidiaries, including (i) its ownership of 50,226,967 ETP Common Units; (ii) ETE’s 100% equity interest in ETP LLC and ETP GP, through which ETE holds the IDRs in ETP; (iii) the 26,266,791 Regency Common Units; (iv) ETE’s 100% equity interests in Regency GP LLC and Regency GP, through which ETE holds the IDRs in Regency.

Borrowings bear interest, at ETE’s option, at either the Eurodollar rate plus an applicable margin or the alternative base rate. The alternative base rate used to calculate interest on base rate loans is calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, or an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are based upon ETE’s leverage ratio and range from 2.75% to 3.75% for Eurodollar loans and from 1.75% to 2.75% for base rate loans. The commitment fee payable on the unused portion of the Parent Company Credit Agreement is based on ETE’s leverage ratio and ranges from 0.50% to 0.75%.

In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ETE’s and the other grantors’ tangible and intangible assets.

ETP Credit Facility

ETP maintains a revolving credit facility (the “ETP Credit Facility”) that 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 is 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.

The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of its current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as ETP’s other current and future unsecured debt.

As of March 31, 2011, ETP had a balance of $553.5 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.42 billion taking into account letters of credit of approximately $24.9 million. The weighted average interest rate on the total amount outstanding as of March 31, 2011 was 0.81%.

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 Regency Credit Facility matures 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 is calculated using the greater 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.

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 March 31, 2011.

10.

REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

In connection with the Regency Transactions completed in May 2010, ETE issued 3,000,000 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 long-term liability in our condensed consolidated balance sheet as of March 31, 2011. The Preferred Units were issued in a private placement at a stated price of $100 per unit and are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit. The Preferred Units will automatically convert on the fourth anniversary of the date of issuance into an amount of ETE Common Units equal in value to the issue

price plus any accrued but unpaid distributions plus a specified premium equal to the lesser of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance of the Preferred Units. ETE may choose, at its sole option, to pay 50% of the conversion consideration based on the issue price plus any accrued but unpaid distributions in cash. ETE may elect to redeem all, but not less than all, of the Preferred Units beginning on the third anniversary of the date of issuance for ETE Common Units or cash equal to the issue price plus a premium paid out in ETE Common Units, equal to the greater of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance. GE EFS also has certain rights to force ETE to redeem or convert the outstanding Preferred Units for specified consideration upon the occurrence of certain extraordinary events involving ETE or ETP. Holders of the Preferred Units have no voting rights, except that approval of a majority of the Preferred Units is needed to approve any amendment to ETE’s Partnership Agreement that would result in (i) any increase in the size of the class of Preferred Units, (ii) any alteration or change to the rights, preferences, privileges, duties, or obligations of the Preferred Units or (iii) any other matter that would adversely affect the rights or preferences of the Preferred Units, including in relation to other classes of ETE partnership interests. During the three months ended March 31, 2011, we recorded a non-cash charge of approximately $15.0 million to increase the carrying value of the Preferred Units to the estimated fair value of $332.6 million.

Regency Preferred Units

Regency has 4,371,586 Regency Preferred Units outstanding at March 31, 2011, which were convertible into 4,614,250 Regency Common Units. If outstanding on September 2, 2029, the Regency Preferred Units are mandatorily redeemable for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed quarterly cash distributions of $0.445 per unit 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 (1)
Balance as of December 31, 2010		4,371,586	$	70,943
Accretion to redemption value		—		48

Ending balance as of March 31, 2011		4,371,586	$	70,991

(1)

This amount will be accreted to $80 million plus any accrued and unpaid distributions at September 2, 2029.

11.

PARTNERS’ CAPITAL:

Common Units Issued

The change in ETE Common Units during the three months ended March 31, 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, March 31, 2011		222,972,708

Sale 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 issuance of units by ETP or Regency (excluding unit issuances to the Parent Company) as a capital transaction. If ETP or Regency issue units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether its investment has been impaired, in which case a provision would be reflected in our statements of operations. The Parent Company did not recognize any impairment related to the issuance of ETP or Regency Common Units during the three months ended March 31, 2011.

As a result of ETP’s issuances of Common Units, we have recognized increases in partners’ capital of $7.2 million for the three months ended March 31, 2011.

Sale of Common Units by ETP

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 three months ended March 31, 2011, ETP received proceeds from units issued pursuant to this agreement of approximately $57.4 million, net of commissions, which were used for general partnership purposes. Approximately $116.8 million of ETP’s Common Units remain available to be issued under the agreement based on trades initiated through March 31, 2011.

On April 1, 2011, ETP issued 14,202,500 Common Units representing limited partner interests at $50.52 per Common Unit in a public offering. Proceeds, net of commissions, of approximately $695.5 million from the offering 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.

Sale of Common Units by Regency

On May 2, 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 ETP-Regency LLC, 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.

On February 18, 2011, the Parent Company paid a cash distribution for the three months ended December 31, 2010 of $0.54 per Common Unit, or $2.16 annualized, to Unitholders of record at the close of business on February 7, 2011.

On April 26, 2011, the Parent Company announced the declaration of a cash distribution for the three months ended March 31, 2011 of $0.56 per Common Unit, or $2.24 annualized. This distribution will be paid on May 19, 2011 to Unitholders of record at the close of business on May 6, 2011.

The total amounts of distributions declared during the three months ended March 31, 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):


	Three Months Ended March 31,
	2011		2010
Limited Partners	$	124,848	$	120,388
General Partner interest		388		374

Total distributions declared	$	125,236	$	120,762

ETP’s Quarterly Distributions of Available Cash

On February 14, 2011, ETP paid a cash distribution for the three months ended December 31, 2010 of $0.89375 per ETP Common Unit, or $3.575 annualized, to ETP Unitholders of record at the close of business on February 7, 2011.

On April 26, 2011, ETP announced the declaration of a cash distribution for the three months ended March 31, 2011 of $0.89375 per ETP Common Unit, or $3.575 annualized. This distribution will be paid on May 16, 2011 to ETP Unitholders of record at the close of business on May 6, 2011.

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


	Three Months Ended March 31,
	2011		2010
Limited Partners:
Common Units	$	186,321	$	170,921
Class E Units		3,121		3,121
General Partner interest		4,896		4,880
Incentive Distribution Rights		103,182		94,917

Total distributions declared by ETP	$	297,520	$	273,839

Regency’s Quarterly Distributions of Available Cash

On February 14, 2011, Regency paid a cash distribution for the three months ended December 31, 2010 of $0.445 per Regency Common Unit, or $1.78 annualized to Regency Unitholders of record at the close of business on February 7, 2011.

On April 26, 2011, Regency announced the declaration of a cash distribution for the three months ended March 31, 2011 of $0.445 per Regency Common Unit, or $1.78 annualized. This distribution will be paid on May 13, 2011 to Regency Unitholders of record at the close of business on May 6, 2011.

The total amounts of Regency distributions declared during the three months ended March 31, 2011 were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):


	Three Months Ended March 31,
	2011		2010
Limited Partners	$	64,895	$	—
General Partner interest		1,269		—
Incentive Distribution Rights		1,114		—

Total distributions declared by Regency	$	67,278	$	—

Accumulated Other Comprehensive Income (Loss)

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


	March 31, 2011			December 31, 2010
Net (losses) gains on commodity related hedges	$	(10,231	)	$	14,146
Unrealized gains on available-for-sale securities		1,526			918
Noncontrolling interest		7,923			(10,266	)

Total AOCI, net of tax	$	(782	)	$	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 three months ended March 31, 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 March 31, 2011 a total of 105,201 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $2.0 million in compensation expense over a weighted average period of 2.4 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the three months ended March 31, 2011, ETP employees were granted a total of 322,700 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 $53.79 per unit. As of March 31, 2011 a total of 2,248,351 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $70.0 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.

Regency Unit-Based Compensation Plans

Common Unit Options

During the three months ended March 31, 2011, no Regency Common Unit options were granted. As of March 31, 2011, a total of 174,850 Regency Common Unit options remain vested and exercisable, with a weighted average exercise price of $22.15 per Regency Common Unit option.

Phantom Units

During the three months ended March 31, 2011, no Regency phantom units were granted. As of March 31, 2011, a total of 677,220 Regency Phantom Units remain unvested, with a weighted average exercise price of $24.62. We expect to recognize a total of $13.4 million in compensation expense over a weighted average period of 4.3 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 March 31,
	2011		2010
Current expense:
Federal	$	5,102	$	1,318
State		3,996		3,158

Total		9,098		4,476

Deferred expense:
Federal		188		694
State		617		41

Total		805		735

Total income tax expense	$	9,903	$	5,211

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 — FEP

FEP has a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP has guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by Kinder Morgan Energy Partners (“KMP”). Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if ETP’s ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012 and amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate.

As of March 31, 2011, FEP had $962.5 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 $481.3 million, which was not reflected in our condensed consolidated balance sheet. The weighted average interest rate on the total amount outstanding as of March 31, 2011 was 3.2%.

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 $5.4 million and $5.9 million for the three months ended March 31, 2011 and 2010.

ETP’s propane operations have an agreement with a subsidiary of 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 and Regency have commitments to make capital contributions to their joint ventures. For the joint ventures that ETP currently has interests in, it expects that future capital contributions will be between $200 million and $230 million during the remainder of 2011, not including contributions to ETP-Regency LLC and ETP’s recently announced joint venture with Enterprise.

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.

Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies and American Electric Power Corporation (“AEP”), were defendants in litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel storage facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas

Litigation.” In 2004, a subsidiary of ETP, La Grange Acquisition, L.P. (“ETC OLP”) acquired the HPL Entities from AEP, at which time AEP agreed, pursuant to a Cushion Gas Litigation Agreement, to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory (approximately $1.00 billion in the aggregate). The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel storage facility. Following an attempted appeal of this decision by AEP, the parties to this litigation entered into a settlement agreement in February 2011 that, among other matters, recognized AEP’s ownership rights to the cushion gas and recognized HPL’s continued right to use this cushion gas through 2013 pursuant to a right to use agreement entered into between predecessors of AEP and HPL in 2001. The settlement agreement also reaffirms the indemnification obligations of AEP in the Cushion Gas Litigation Agreement. As a result of the settlement agreement and the indemnification provisions in the Cushion Gas Litigation Agreement, ETP does not expect that it will have any liability to either AEP or B of A with respect to the matters subject to this litigation.

Other Matters. In addition to those matters described above, 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, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As of March 31, 2011 and December 31, 2010, accruals of approximately $10.6 million and $10.2 million, respectively, were recorded related to deductibles. 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 it is possible that the outcome of a particular matter will result in the payment of an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

No amounts have been recorded in our March 31, 2011 condensed consolidated balance sheets or our December 31, 2010 consolidated balance sheets for contingencies and current litigation matters other than accruals related to environmental matters and deductibles.

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, 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, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies there under, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, we have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.

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 March 31, 2011 and December 31, 2010, accruals related to ETP on an undiscounted basis of $13.0 million and $13.8 million, respectively, were recorded in our condensed 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 $8.2 million, which is included in the aggregate environmental accruals discussed above. Transwestern received approval from the Federal Energy Regulatory Commission (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 March 31, 2011 condensed 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 when, how or if comments will be filed on the direct final rule or if a court ruling would modify the final rule, 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.

In June 2010, the EPA formally proposed modifications to existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The proposed rule modifications, if adopted as drafted by the EPA, 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 cannot predict the final regulatory requirements or the cost to comply with such requirements. The EPA expects to finalize the proposed rules in May 2011 with an effective date targeted for July 2011.

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 March 31, 2011 and 2010, $1.7 million and $1.4 million, respectively, of capital costs and $2.1 million and $1.9 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.

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 condensed 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 March 31, 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, 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 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 condensed 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 as of March 31, 2011 and December 31, 2010:


	March 31, 2011					December 31, 2010
	Notional Volume			Maturity		Notional Volume			Maturity
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)		(28,535,000	)		2011-2012		(38,897,500	)		2011
Swing Swaps IFERC (MMBtu)		(50,617,500	)		2011-2012		(19,720,000	)		2011
Fixed Swaps/Futures (MMBtu)		(7,872,500	)		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)		(27,200,000	)		2011		(28,050,000	)		2011
Fixed Swaps/Futures (MMBtu)		(30,547,500	)		2011		(39,105,000	)		2011
Hedged Item — Inventory (MMBtu)		30,547,500			2011		39,105,000			2011

Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)		1,530,000			2011		(210,000	)		2011
Options — Puts (MMBtu)		20,970,000			2011-2012		26,760,000			2011-2012
Options — Calls (MMBtu)		(20,970,000	)		2011-2012		(26,760,000	)		2011-2012
Propane:
Forwards/Swaps (Gallons)		5,292,000			2011-2012		32,466,000			2011

We expect gains of $13.4 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 as of March 31, 2011 and December 31, 2010:


	March 31, 2011				December 31, 2010
	Notional Volume		Maturity		Notional Volume		Maturity
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)		3,110,000		2011-2012		3,830,000		2011
Propane:
Forwards/Swaps (Gallons)		18,411,960		2011-2012		18,648,000		2011-2012
Natural Gas Liquids:
Forwards/Swaps (Barrels)		1,172,500		2011-2012		1,212,110		2011-2012
WTI Crude Oil:
Forwards/Swaps (Barrels)		370,155		2011-2012		373,655		2011-2012

We expect losses of $19.5 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 a portion of our current and future interest rate exposures by utilizing interest rate swaps in order to achieve our 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 March 31, 2011 and December 31, 2010, none of which were designated as hedges for accounting purposes:


			Notional Amount Outstanding
Entity	Term	Type (1)	March 31, 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	$	400,000
ETP	July 2018	Pay a floating rate and receive a fixed rate of 6.70%	500,000		500,000
Regency	April 2012	Pay a fixed rate of 1.325% and receive a floating rate	250,000		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.

In addition to interest rate swaps, ETP also periodically enters into interest rate swaptions that enable counterparties to exercise options to enter into interest rate swaps with ETP. Swaptions may be utilized when ETP’s targeted benchmark interest rate for anticipated debt issuance is not attainable at that time in the interest rate swap market. Upon issuance of a swaption, ETP receives a premium, which ETP recognizes over the term of the swaption to “Gains (losses) on non-hedged interest rate derivatives” in the condensed consolidated statements of operations. No swaptions were outstanding as of March 31, 2011.

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 condensed consolidated balance sheets. ETP had net deposits with counterparties of $90.0 million and $52.2 million as of March 31, 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 enters into Master International Swap Dealers Association (“ISDA”) 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 condensed consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a balance sheet overview of consolidated derivative assets and liabilities as of March 31, 2011 and December 31, 2010:


	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2011		December 31, 2010		March 31, 2011			December 31, 2010
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	17,915	$	35,031	$	(7,785	)	$	(6,631	)
Commodity derivatives		3,014		9,263		(25,423	)		(14,692	)

		20,929		44,294		(33,208	)		(21,323	)

Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	92,523	$	64,940	$	(82,165	)	$	(72,729	)
Commodity derivatives		—		275		—			—
Interest rate derivatives		27,580		20,790		(26,350	)		(20,922	)
Embedded derivatives in Regency Preferred Units		—		—		(54,448	)		(57,023	)

		120,103		86,005		(162,963	)		(150,674	)

Total derivatives	$	141,032	$	130,299	$	(196,171	)	$	(171,997	)

The commodity derivatives (margin deposits) are recorded in “Other current assets” on our condensed 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 condensed 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 March 31,
	2011			2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(10,892	)	$	34,108
Interest rate derivatives		—			(10,200	)

Total	$	(10,892	)	$	23,908


	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)		Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
			Three Months Ended March 31,
			2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives		Cost of products sold	$	13,539	$	5,315
Interest rate derivatives		Interest expense		—		(7,266	)

Total			$	13,539	$	(1,951	)


	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)		Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
			Three Months Ended March 31,
			2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives		Cost of products sold	$	92	$	1,121

Total			$	92	$	1,121


	Location of Gain/(Loss) Recognized in Income on Derivatives		Amount of Gain/(Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness
			Three Months Ended March 31,
			2011		2010
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives		Cost of products sold	$	6,417	$	(7,384	)

Total			$	6,417	$	(7,384	)


	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2011		2010
Derivatives not designated as hedging instruments:
Commodity derivatives	Cost of products sold	$	8,006	$	21,967
Interest rate derivatives	Gains (losses) on non-hedged interest rate derivatives		1,520		(14,424	)
Embedded Derivatives	Other income		2,575		—

Total		$	12,101	$	7,543

We recognized $17.9 million and $8.8 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 March 31, 2011 and 2010, respectively. In addition, for the three months ended March 31, 2011 and 2010, we recognized unrealized losses of $8.9 million and unrealized gains of $8.1 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 months ended March 31, 2011, the Parent Company received $2.5 million in management fees from Regency related to these services. For the three months ended March 31, 2011 and 2010, the Parent Company paid $2.6 million and $0.1 million in management fees, respectively, to ETP related to these services. In addition, for the three months ended March 31, 2011 ETP recorded $2.3 million from Regency for reimbursement of various general and administrative expenses incurred by ETP.

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 March 31,
	2011		2010
ETP’s Natural Gas Operations:
Sales	$	135,913	$	144,720
Purchases		8,224		6,597

Regency’s Natural Gas Operations:
Sales		74,914		—
Purchases		321		—

ETP’s Propane Operations:
Sales		8,777		10,485
Purchases		169,966		165,764

As of December 31, 2010, a subsidiary of ETP had forward mark-to-market derivatives for approximately 1.7 million gallons of propane at a fair value asset of $0.2 million. All of these forward contracts were settled as of March 31, 2011. In addition, as of March 31, 2011 and December 31, 2010, Titan had forward derivatives accounted for as cash flow hedges of 5.3 million and 32.5 million gallons of propane at fair value assets of $1.4 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 for the three months ended March 31, 2011.

Regency’s contract compression operations provide contract compression services to HPC. HPC also provides transportation service to Regency. For the three months ended March 31, 2011, Regency had revenue of $6.5 million and cost of sales of $4.1 million with HPC.

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


	March 31, 2011		December 31, 2010
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	47,680	$	36,736
Regency’s Natural Gas Operations		29,092		25,539
ETP’s Propane Operations		3,072		2,327
Other		9,285		11,729

Total accounts receivable from related parties:	$	89,129	$	76,331

Accounts payable to related parties:
Enterprise:
ETP’s Natural Gas Operations	$	5,037	$	2,687
Regency’s Natural Gas Operations		598		1,323
ETP’s Propane Operations		13,935		22,985
Other		443		356

Total accounts payable to related parties:	$	20,013	$	27,351

ETP’s net imbalance receivable from Enterprise	$	608	$	1,360

Regency’s net imbalance receivable from Enterprise	$	1,876	$	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:


	March 31, 2011		December 31, 2010
Deposits paid to vendors	$	90,007	$	52,192
Prepaid expenses and other		61,012		57,167

Total other current assets	$	151,019	$	109,359

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	March 31, 2011		December 31, 2010
Interest payable	$	219,340	$	191,466
Customer advances and deposits		54,174		111,448
Accrued capital expenditures		106,160		87,260
Accrued wages and benefits		33,890		76,592
Taxes payable other than income taxes		57,789		36,204
Income taxes payable		17,317		8,344
Other		56,799		56,374

Total accrued and other current liabilities	$	545,469	$	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.

ETP and Regency related party transactions 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 March 31, 2011:
Revenues from external customers	$	1,676,047	$	315,559		$	—		$	(2,486	)	$	1,989,120
Intersegment revenues		11,530		1,693			—			(13,223	)		—
Depreciation and amortization		95,964		40,236			3,056			—			139,256
Interest expense, net of interest capitalized		107,240		20,007			40,942			(260	)		167,929
Equity in earnings of affiliates		1,633		23,808			—			—			25,441
Income tax expense (benefit)		10,597		(32	)		(662	)		—			9,903
Net income (loss)		247,202		14,305			(62,415	)		—			199,092

Three months ended March 31, 2010:
Revenues from external customers	$	1,871,981	$	—		$	—		$	—		$	1,871,981
Intersegment revenues		—		—			—			—			—
Depreciation and amortization		83,276		—			3,055			—			86,331
Interest expense, net of interest capitalized		104,962		—			16,709			—			121,671
Equity in earnings of affiliates		6,181		—			—			—			6,181
Income tax expense (benefit)		5,924		—			(713	)		—			5,211
Net income (loss)		240,111		—			(36,029	)		—			204,082


	As of March 31, 2011			As of December 31, 2010
Total assets:
Investment in ETP	$	12,251,446		$	12,149,992
Investment in Regency		4,784,621			4,770,204
Corporate and Other		498,366			469,221
Adjustments and Eliminations		(24,271	)		(10,687	)

Total	$	17,510,162		$	17,378,730


	As of March 31, 2011			As of December 31, 2010
Advances to and investments in affiliates:
Investment in ETP	$	19,677		$	8,723
Investment in Regency		1,332,900			1,351,256

Total	$	1,352,577		$	1,359,979


	Three Months Ended March 31,
	2011			2010
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP	$	203,770		$	194,664
Investment in Regency		68,633			—

Total	$	272,403		$	194,664

19.

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS

(unaudited)


	March 31, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	58,093		$	27,247
Accounts receivable from related companies		772			171
Other current assets		2,427			864

Total current assets		61,292			28,282

ADVANCES TO AND INVESTMENTS IN AFFILIATES		2,219,143			2,231,722
INTANGIBLES AND OTHER ASSETS, net		28,305			29,118

Total assets	$	2,308,740		$	2,289,122


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable to related companies	$	8,538		$	6,654
Accrued and other current liabilities		78,044			44,200

Total current liabilities		86,582			50,854

LONG-TERM DEBT, less current maturities		1,800,000			1,800,000
SERIES A CONVERTIBLE PREFERRED UNITS		332,640			317,600

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
General Partner		440			520
Limited Partners – Common Unitholders (222,972,708 and 222,941,172 units authorized, issued and outstanding at March 31, 2011 and December 31, 2010, respectively)		89,860			115,350
Accumulated other comprehensive income (loss)		(782	)		4,798

Total partners’ capital		89,518			120,668

Total liabilities and partners’ capital	$	2,308,740		$	2,289,122

STATEMENTS OF OPERATIONS

(unaudited)


	Three Months Ended March 31,
	2011			2010
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(1,842	)	$	(2,336	)

OTHER INCOME (EXPENSE):
Interest expense		(40,939	)		(16,706	)
Equity in earnings of affiliates		146,642			146,378
Losses on non-hedged interest rate derivatives		—			(14,424	)
Other, net		(15,159	)		(124	)

INCOME BEFORE INCOME TAXES		88,702			112,788
Income tax expense		62			11

NET INCOME		88,640			112,777
GENERAL PARTNER’S INTEREST IN NET INCOME		274			349

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	88,366		$	112,428

STATEMENTS OF CASH FLOWS

(unaudited)


	Three Months Ended March 31,
	2011			2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	151,609		$	118,864

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		—			11,421
Principal payments on debt		—			(9,523	)
Distributions to Partners		(120,763	)		(120,762	)

Net cash used in financing activities		(120,763	)		(118,864	)

INCREASE IN CASH AND CASH EQUIVALENTS		30,846			—
CASH AND CASH EQUIVALENTS, beginning of period		27,247			62

CASH AND CASH EQUIVALENTS, end of period	$	58,093		$	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 “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 March 31, 2011, our equity interests consisted of:


	General Partner Interest (as a % of total partnership interest)			Incentive Distribution Rights (“IDRs”)			Common Units
ETP		1.8	%		100	%		50,226,967
Regency		2.0	%		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:

•

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 more than 17,500 miles of gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

•

Recent Developments

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”), a wholly owned subsidiary of Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”), from Louis Dreyfus for approximately $1.97 billion in cash, including preliminary working capital and other adjustments. 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 and Regency contributed approximately $591 million to ETP-Regency LLC upon closing 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, one of the largest NGL storage, distribution and trading complexes in North America. Its West Texas Pipeline transports NGLs through a 1,066-mile 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 is expected to significantly expand our subsidiaries’ asset portfolios, adding a NGL platform with storage, transportation and fractionation capabilities. Additionally, this acquisition will provide additional consistent fee-based revenues.

On May 5, 2011, Lone Star 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. ETP also announced that they are in negotiations with other pipeline operators to secure pipeline capacity that will provide NGL transportation from Jackson County, Texas to Mont Belvieu, Texas. In the event they determine that it is more prudent to build a new pipeline rather than secure pipeline capacity through another pipeline operator, they will construct a 130-mile, 20-inch NGL pipeline from the processing facility they plan to build in Jackson County to Mont Belvieu. This pipeline will provide capacity for NGL barrels from the Eagle Ford Shale or from a potential NGL pipeline from West Texas. The capacity of the proposed 20-inch pipeline is expected to be approximately 340,000 Bbls/d.

On April 26, 2011, ETP announced that it has agreed to form a 50/50 joint venture with Enterprise Products Partners L.P. (together with its subsidiaries “Enterprise”) to design and construct a crude oil pipeline from Cushing, Oklahoma to Houston, Texas. Utilizing new and existing pipelines, the 584-mile project will originate at Enterprise’s 3.1 million barrel crude oil storage facility in Cushing. Enterprise and ETP will each contribute existing assets to the joint venture, including ETP’s 240-mile, 24-inch diameter natural gas pipeline in East Texas, which will comprise approximately 40% of the proposed system.

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 March 31,
	2011			2010			Change
Revenues	$	1,989,120		$	1,871,981		$	117,139
Cost of products sold		1,201,426			1,224,865			(23,439	)

Gross margin		787,694			647,116			140,578
Operating expenses		220,696			170,748			49,948
Depreciation and amortization		139,256			86,331			52,925
Selling, general and administrative		63,499			51,109			12,390

Operating income		364,243			338,928			25,315
Interest expense, net of interest capitalized		(167,929	)		(121,671	)		(46,258	)
Equity in earnings of affiliates		25,441			6,181			19,260
Losses on disposal of assets		(1,754	)		(1,864	)		110
Gains (losses) on non-hedged interest rate derivatives		1,520			(14,424	)		15,944
Other, net		(12,526	)		2,143			(14,669	)
Income tax expense		(9,903	)		(5,211	)		(4,692	)

Net income	$	199,092		$	204,082		$	(4,990	)

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 March 31,
	2011			2010			Change
Selling, general and administrative	$	(1,842	)	$	(2,336	)	$	494
Interest expense, net of interest capitalized		(40,939	)		(16,706	)		(24,233	)
Equity in earnings of affiliates		146,642			146,378			264
Losses on non-hedged interest rate derivatives		—			(14,424	)		14,424
Other, net		(15,159	)		(124	)		(15,035	)

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 $143.2 million and $146.4 million for the three months ended March 31, 2011 and 2010, respectively. An analysis of ETP’s results is included in “Segment Operating Results” below. The three months ended March 31, 2011 also reflect the equity in earnings from Regency of $3.4 million; no amounts are reflected in the prior period which occurred prior to our acquisition of a controlling interest in Regency on May 26, 2010.

Interest Expense. For the three months ended March 31, 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 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. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings.

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 condensed 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 March 31,
	2011			2010			Change
Investment in ETP	$	247,202		$	240,111		$	7,091
Investment in Regency		14,305			—			14,305
Corporate and Other		(62,415	)		(36,029	)		(26,386	)

Net income	$	199,092		$	204,082		$	(4,990	)

Investment in ETP


	Three Months Ended March 31,
	2011			2010			Change
Revenues	$	1,687,577		$	1,871,981		$	(184,404	)
Cost of products sold		994,457			1,224,865			(230,408	)

Gross margin		693,120			647,116			46,004
Operating expenses		188,489			170,748			17,741
Depreciation and amortization		95,964			83,276			12,688
Selling, general and administrative		45,532			48,754			(3,222	)

Operating income		363,135			344,338			18,797
Interest expense, net of interest capitalized		(107,240	)		(104,962	)		(2,278	)
Equity in earnings of affiliates		1,633			6,181			(4,548	)
Losses on disposal of assets		(1,726	)		(1,864	)		138
Gains on non-hedged interest rate derivatives		1,779			—			1,779
Other, net		218			2,342			(2,124	)
Income tax expense		(10,597	)		(5,924	)		(4,673	)

Net income	$	247,202		$	240,111		$	7,091

Gross Margin. For the three months ended March 31, 2011 compared to the three months ended March 31, 2010, ETP’s gross margin increased primarily due to the net impact of the following:

•

Gross margin related to ETP’s intrastate transportation and storage operations increased $14.1 million between periods due to (i) an increase of $7.8 million in storage margin primarily driven by carrying a larger volume of inventory out of the withdrawal season that was subject to mark-to-market impact, (ii) an increase of $5.2 million in margin from the sales of natural gas and other activities primarily due to more favorable impacts from system optimization activities, and (iii) an increase of $1.9 million in transportation fees due to higher volumes driven by increased production by ETP’s customers in areas where ETP’s assets are located. These increases were partially offset by a decrease of $0.7 million in retained fuel revenues due to less favorable pricing.

•

Revenues from ETP’s interstate transportation operations increased by $36.8 million between periods primarily due to incremental revenues for the Tiger pipeline which was placed into service in December 2010.

•

Gross margin related to ETP’s midstream operations increased $5.9 million between periods primarily due to higher volumes resulting from more production by ETP’s customers in addition to favorable processing conditions.

•

Gross margin related to ETP’s retail propane and other retail propane related operations decreased $9.6 million primarily due to a decrease in sales volumes driven by weather patterns and customer conservation.

Operating Expenses. For the three months ended March 31, 2011 compared to the three months ended March 31, 2010, ETP’s operating expenses increased primarily due to an incremental $7.0 million in ad valorem taxes related to the Tiger pipeline which was placed in service in December 2010 and an increase of $5.4 million in employee-related costs associated with ETP’s natural gas businesses. The remainder of the increase in operating expenses was primarily related to higher maintenance and operating expenses and an increase in professional fees.

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 months ended March 31, 2011, ETP’s selling, general and administrative expenses decreased primarily due to lower employee-related costs.

Interest Expense. ETP’s interest expense increased $2.3 million for the three months ended March 31, 2011 compared to the same period in the previous year principally due to higher borrowings under ETP’s revolving credit facility (the “ETP Credit Facility”) to fund growth projects. ETP’s interest expense is presented net of capitalized interest and allowance for debt funds used during construction, which totaled $1.8 million and $1.1 million for the three months ended March 31, 2011 and 2010, respectively.

Equity in Earnings of Affiliates. ETP’s equity in earnings of affiliates decreased $4.5 million for the three months ended March 31, 2011 compared to the same period in the previous year primarily due to ETP’s transfer of substantially all of its interest in MEP to ETE on May 26, 2010. For the three months ended March 31, 2011, equity in earnings of affiliates primarily consisted of ETP’s proportionate share of the earnings of FEP.

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.

Investment in Regency


	Three Months Ended March 31,
	2011			2010		Change
Revenues	$	317,252		$	—	$	317,252
Cost of products sold		216,261			—		216,261

Gross margin		100,991			—		100,991
Operating expenses		33,672			—		33,672
Depreciation and amortization		40,236			—		40,236
Selling, general and administrative		18,997			—		18,997
Losses on disposal of assets		28			—		28

Operating income		8,058			—		8,058
Interest expense, net of interest capitalized		(20,007	)		—		(20,007	)
Equity in earnings of affiliates		23,808			—		23,808
Other, net		2,414			—		2,414
Income tax benefit		32			—		32

Net income	$	14,305		$	—	$	14,305

ETE obtained control of Regency on May 26, 2010. Changes between periods are 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 for the three months ended March 31, 2011 include its equity in earnings related to its 49.9% interest in MEP.

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.

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 segments, primarily for construction of new pipelines and compression, for which ETP expects to spend between $600 million and $650 million for the remainder of 2011;

•

growth capital expenditures for its interstate transportation segment, excluding capital contributions to its joint ventures as discussed below, for the construction of new pipelines for which ETP expects to spend between $160 million and $190 million for the remainder of 2011;

•

growth capital expenditures for its retail propane segment of between $15 million and $25 million for the remainder of 2011; and

•

maintenance capital expenditures of between $90 million and $100 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 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 on the joint ventures that it currently has interests in will be between $250 million and $300 million for the remainder of 2011, including $50 million to $75 million of contributions to ETP-Regency LLC (renamed Lone Star as discussed above in “Recent Developments”). This does not include any contributions ETP may make related to its recently announced joint venture with Enterprise.

ETP may enter into acquisitions, including the potential acquisition of new pipeline systems and propane operations. ETP closed the LDH acquisition on May 2, 2011. ETP’s 70% share of the purchase price was $1.38 billion, which was partially funded with borrowings under the ETP Credit Facility.

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 $57.4 million in net proceeds during the three months ended March 31, 2011 under ETP’s equity distribution program, as described in Note 11 to our condensed consolidated financial statements. As of March 31, 2011, in addition to approximately $60.1 million of cash on hand, ETP had available capacity under the ETP Credit Facility of approximately $1.42 billion. Based on current estimates, ETP expects to utilize its revolver capacity, 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.

On April 1, 2011, ETP issued 14,202,500 ETP Common Units representing limited partner interests at $50.52 per ETP Common Unit in a public offering. Proceeds of approximately $695.5 million, net of commissions, from the offering 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.

In April 2011, ETP filed a registration statement with the SEC covering its Distribution Reinvestment Plan (the “DRIP”). The DRIP provides ETP’s Unitholders of record and beneficial owners of its 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 Common Units under the DRIP.

Regency Energy Partners

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 March 31, 2011, in addition to approximately $24.7 million of cash on hand, Regency had available capacity under the Regency Credit Facility of approximately $524.5 million.

Regency expects its growth capital expenditures to be approximately $253.0 million in 2011, which includes approximately $155.0 million for its Gathering and Processing operations, mostly in South Texas, $78.0 million for its Contract Compression operations, $12.0 million for its Contract Treating operations, and $8.0 million for its Corporate and Others operations. In addition, Regency expects its maintenance capital expenditures to be approximately $14.0 million in 2011.

Regency expects that HPC will fund its expected 2011 growth capital expenditures of $42.0 million (100% basis) 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.

Three months ended March 31, 2011 compared to three months ended March 31, 2010. Cash provided by operating activities during 2011 was $358.1 million as compared to $475.0 million for 2010. Net income was $199.1 million and $204.1 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 $173.4 million and $97.3 million and changes in operating assets and liabilities of $37.7 million and $161.7 million for 2011 and 2010, respectively.

The non-cash activity in 2011 and 2010 consisted primarily of depreciation and amortization of $139.3 million and $86.3 million, respectively. In addition, non-cash compensation expense was $11.4 million and $7.7 million for 2011 and 2010, respectively.

Cash paid for interest, net of interest capitalized, was $138.0 million and $145.4 million for the three months ended March 31, 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.

Three months ended March 31, 2011 compared to three months ended March 31, 2010. Cash used in investing activities during 2011 was $290.3 million as compared to $266.1 million for 2010. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2011 were $279.6 million, including changes in accruals of $2.5 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2010 of $119.7 million, including changes in accruals of $22.2 million. In addition, in 2011 our subsidiaries paid cash for acquisitions of $3.1 million and made advances to joint ventures of $11.1 million. In 2010, ETP paid cash for acquisitions of $149.6 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.

Three months ended March 31, 2011 compared to three months ended March 31, 2010. Cash used in financing activities during 2011 was $11.1 million as compared to cash provided by financing activities of $107.2 million for 2010. In 2011, ETP received $57.4 million in net proceeds from offerings of common units under ETP’s equity distribution program, as compared to $504.5 million in 2010, which included $81.0 million under ETP’s equity distribution program (see Note 11 to our condensed consolidated financial statements). During 2011, we had a consolidated net increase in our debt level of $233.5 million as compared to a net decrease of $162.1 million for 2010. We paid distributions of $120.8 million to our partners in 2011 and in 2010. In addition, during 2011 and 2010, ETP paid distributions of $130.1 million and $114.4 million, respectively, on limited partner interests other than those held by the Parent Company and Regency paid distributions of $49.6 million on limited partner interests other than those held by the Parent Company in 2011. These distributions are reflected as distributions to noncontrolling interests on our condensed consolidated statements of cash flows.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	March 31, 2011			December 31, 2010
Parent Company Indebtedness:
ETE Senior Notes	$	1,800,000		$	1,800,000
Subsidiary Indebtedness:
ETP Senior Notes		5,050,000			5,050,000
Regency Senior Notes		850,000			850,000
Transwestern Senior Unsecured Notes		870,000			870,000
HOLP Senior Secured Notes		103,127			103,127
ETP Revolving Credit Facility		553,524			402,327
Regency Revolving Credit Facility		360,000			285,000
Other long-term debt		8,848			9,671
Unamortized discounts, net		(6,037	)		(6,013	)
Fair value adjustments related to interest rate swaps		15,857			17,260

Total debt	$	9,605,319		$	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.

The aggregate principal amount 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.

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 March 31, 2011, ETP had a balance of $553.5 million outstanding under the ETP Credit Facility, and the amount available under the credit facility was $1.42 billion, taking into account letters of credit of approximately $24.9 million. The weighted average interest rate on the total amount outstanding at March 31, 2011 was 0.81%. In April 2011, ETP repaid the outstanding borrowings under the ETP Credit Facility with proceeds from its Common Unit Offering. On May 2, 2011, ETP funded a portion of its proportionate share of the purchase price paid by ETP-Regency LLC to acquire all of the membership interest in LDH from Louis Dreyfus under borrowings from the ETP Credit Facility.

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, which is currently 2.5% of the average daily amount of such lender’s letter of credit exposure, 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 March 31, 2011, there was a balance outstanding in the Regency Credit Facility of $360.0 million in revolving credit loans and approximately $15.5 million in letters of credit. The total amount available under the Regency Credit Facility, as of March 31, 2011, which is reduced by any letters of credit, was approximately $524.5 million. The weighted average interest rate on the total amount outstanding as of March 31, 2011 was 3.1%. On May 2, 2011, Regency borrowed approximately $387.7 million under the Regency Credit Facility to fund a portion of its proportionate share of the purchase price paid by ETP-Regency LLC to acquire all of the membership interest in LDH from Louis Dreyfus.

FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP has guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by Kinder Morgan Energy Partners (“KMP”). Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if ETP’s ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012. Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate.

As of March 31, 2011, FEP had $962.5 million of outstanding borrowings issued under the FEP Facility. ETP’s contingent obligation with respect to its guaranteed portion of FEP’s outstanding borrowings was $481.3 million, which is not reflected on our condensed consolidated balance sheets as of March 31, 2011. The weighted average interest rate on the total amount outstanding as of March 31, 2011 was 3.2%.

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.


	Three Months Ended March 31,
	2011		2010
Limited Partners	$	124,848	$	120,388
General Partner interest		388		374

Total distributions	$	125,236	$	120,762

Cash Distributions Received from Subsidiaries

The total amount of distributions the Parent Company received 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:


	Three Months Ended March 31,
	2011		2010
Distributions from ETP:
Limited Partners ⁽¹⁾	$	44,890	$	55,860
General Partner interest		4,896		4,880
Incentive Distribution Rights		103,182		94,917

Total distributions from ETP		152,968		155,657

Distributions from Regency:
Limited Partners		11,689		—
General Partner interest		1,269		—
Incentive Distribution Rights		1,114		—

Total distributions from Regency		14,072		—

Total distributions received	$	167,040	$	155,657

⁽¹⁾	As of March 31, 2011, we held 50,226,967 ETP Common Units. This amount reflects the redemption of 12.3 million ETP Common Units in connection with the Regency Transactions in May 2010.

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

On April 26, 2011, ETP announced the declaration a cash distribution for the three months ended March 31, 2011 of $0.89375 per ETP Common Unit, or $3.575 annualized. This distribution will be paid on May 16, 2011 to ETP Unitholders of record at the close of business on May 6, 2011.


	Three Months Ended March 31,
	2011		2010
Limited Partners:
Common Units	$	186,321	$	170,921
Class E Units		3,121		3,121

General Partner interest		4,896		4,880
Incentive Distribution Rights		103,182		94,917

Total distributions	$	297,520	$	273,839

Cash Distributions Paid by Regency

On February 14, 2011, Regency paid a cash distribution for the three months ended December 31, 2010 of $0.445 per Regency Common Unit, or $1.78 annualized, to Regency Unitholders of record at the close of business on February 7, 2011.

The total amounts of Regency distributions declared since the date of acquisition were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):


	Three Months Ended March 31,
	2011		2010
Limited Partners	$	64,895	$	—
General Partner interest		1,269		—
Incentive Distribution Rights		1,114		—

Total distributions	$	67,278	$	—

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 condensed 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 March 31, 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 condensed 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 condensed 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.


	March 31, 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		(28,535,000	)	$	10,255		$	2,475		(38,897,500	)	$	(2,334	)	$	304
Swing Swaps IFERC		(50,617,500	)		1,045			6,438		(19,720,000	)		(2,086	)		2,228
Fixed Swaps/Futures		(7,872,500			(7,851	)		3,435		(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		(27,200,000	)		(331	)		111		(28,050,000	)		722			322
Fixed Swaps/Futures		(30,547,500	)		(2,691	)		13,575		(39,105,000	)		8,599			16,837

Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures		1,530,000			62			673		(210,000	)		232			93
Options — Puts		20,970,000			8,006			5,665		26,760,000			10,545			7,125
Options — Calls		(20,970,000	)		3,843			1,057		(26,760,000	)		4,812			1,565
Propane:
Forwards/Swaps		5,292,000			1,395			727		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.


	March 31, 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		3,110,000	$	1,397		$	1,461		3,830,000	$	2,053		$	1,684
Propane:
Forwards/Swaps		18,411,960		(6,189	)		2,528		18,648,000		(4,203	)		2,277
Natural Gas Liquids:
Forwards/Swaps		1,172,500		(11,530	)		5,410		1,212,110		(6,288	)		4,910
WTI Crude:
Forwards/Swaps		370,155		(7,542	)		3,976		373,655		(3,581	)		3,501

Interest Rate Risk

As of March 31, 2011, ETP had $553.5 million of variable rate debt outstanding under its revolving credit facilities and Regency had $360.0 million of variable rate debt outstanding under its revolving credit facilities. ETE had no variable rate debt outstanding as of March 31, 2011. A hypothetical change of 100 basis points would result in a change to

interest expense of $9.1 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. We, ETP and Regency had the following interest rate swaps outstanding as of March 31, 2011 and December 31, 2010 (dollars in thousands), none of which are designated as hedges for accounting purposes:

Notional Amount Outstanding

Entity

Term

Type

March 31,
2011

December 31,
2010

ETP

August 2012⁽¹⁾

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

400,000

ETP

July 2018

Pay a floating rate 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⁾	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.

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 $0.1 million as of March 31, 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 $400.0 million of forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until August 2012 when the swaps are settled.

ETP periodically enters into interest rate swaptions when its targeted benchmark interest rates for anticipated debt issuances are not attainable at the time in the interest rate swap market. Swaptions enable counterparties to exercise options to enter into interest rate swaps with ETP in exchange for premiums. As of March 31, 2011, ETP had no swaptions outstanding.

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.

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 has entered into Master International Swap Dealers Association (“ISDA”) 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 condensed 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 March 31, 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. As of March 31, 2011, no significant changes have been made to Regency’s accounting systems; however, certain of its controls and procedures have been changed to conform to the existing controls of our other subsidiaries. Additional changes, including the transition of the Regency’s accounting systems, are expected to be completed during the second quarter of 2011. None of these changes were in response to an identified deficiency or weakness in Regency’s internal control over financial reporting.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended March 31, 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 Condensed Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

ITEM 1A. RISK FACTORS

ETP’s and Regency’s recently announced transactions present several risks. Many of those risks are similar to the risks associated with their existing businesses, 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.

Risks Related to Our Business

ETP and Regency do not control, and therefore may not be able to cause or prevent certain actions by, certain of their joint ventures.

Certain of ETP’s and Regency’s joint ventures have their own governing boards, and ETP or Regency may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for ETP or Regency to cause the joint venture entity to take actions that ETP or Regency believe would be in their or the joint venture’s best interests. Likewise, ETP or Regency may be unable to prevent actions of the joint venture.

The profitability of certain activities in ETP’s or Regency’s NGL and refined products storage business, NGL transportation business and off-gas processing and fractionating business are largely dependent upon market demand for NGLs and refined products, which has been volatile, and competition in the market place, both of which are factors that are beyond our control.

ETP’s and Regency’s NGL and refined products storage revenues are primarily derived from fixed capacity arrangements between ETP or Regency and their customers. However, a portion of ETP’s and Regency’s revenue is derived from fungible storage and throughput arrangements, under which revenue is more dependent upon demand for storage from customers. Demand for these services may fluctuate as a result of changes in commodity prices. ETP’s and Regency’s NGL and refined products storage assets are primarily located in the Mont Belvieu area, which is a significant storage distribution and trading complex with multiple industry participants, any one of which could compete for the business of ETP’s and Regency’s existing and potential customers. Any loss of business from existing customers or ETP’s or Regency’s inability to attract new customers could have an adverse effect on our results of operations.

Revenue from ETP’s and Regency’s NGL transportation systems is exposed to risks due to fluctuations in demand for transportation as a result of unfavorable commodity prices and competition from nearby pipelines. ETP and Regency receive substantially all of their transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to ETP’s or Regency’s transportation system. ETP or Regency may not be able to renew these contracts or execute new customer contracts on favorable terms if NGL prices decline and demand for ETP’s or Regency’s transportation services decreases. Any loss of existing customers due to decreased demand for ETP’s or Regency’s services or competition from other transportation service providers could have a negative impact on our revenues and have an adverse effect on our results of operations.

Revenue from ETP’s and Regency’s off-gas processing and fractionating system in south Louisiana is exposed to risks due to the low concentration of suppliers near the facilities and the possibility that connected refineries may not provide ETP or Regency with sufficient off-gas for processing at their facilities. The connected refineries may also experience outages due to maintenance issues and severe weather, such as hurricanes. ETP and Regency receive revenues primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of ETP’s and Regency’s off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for ETP’s or Regency’s off-gas processing and fractionation services and could have an adverse effect on our results of operations.

The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:

•

the impact of weather on the demand for oil, natural gas and NGLs;

•

the level of domestic oil and natural gas production;

•

the availability of imported oil, natural gas and NGLs;

•

actions taken by foreign oil and gas producing nations;

•

the availability of local transportation systems;

•

the price, availability and marketing of competitive fuels;

•

the demand for electricity;

•

the impact of energy conservation efforts; and

•

the extent of governmental regulation and taxation.

Certain of ETP’s and Regency’s assets may become subject to regulation.

Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. The 1,066-mile West Texas Pipeline, which ETP and Regency acquired as part the LDH acquisition, transports NGLs within the state of Texas and is subject to regulation by the Texas Railroad Commission (“TRRC”). This NGL transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. Such services must be provided in a manner that is just, reasonable and non-discriminatory. ETP and Regency believe that this NGL system

does not provide interstate service and that it is thus not subject to FERC jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. We cannot guarantee that the jurisdictional status of this NGL pipeline system will remain unchanged, however, should it be found jurisdictional, the FERC’s rate-making methodologies may, among other things, delay the use of rates that reflect increased costs and subject ETP or Regency to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect revenues and cash flow related to these assets.

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.

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.


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

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.

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.


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

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.

10.2	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.

31.1			Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1			Certification of President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

*	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: May 6, 2011	By:	/s/John W. McReynolds
		John W. McReynolds
		President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)