Edgar Filing: Energy Transfer Equity, L.P.

ETE- 9.30.2011-Q3

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2011



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

Commission file number 1-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)



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

3738 Oak Lawn Avenue, Dallas, Texas 75219

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

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

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



Large accelerated filer	ý	Accelerated filer	¨

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

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

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

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

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FORM 10-Q

TABLE OF CONTENTS

Energy Transfer Equity, L.P. and Subsidiaries



PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

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

Consolidated Statements of Operations – Three and Nine Months Ended September 30, 2011 and 2010	3

Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2011 and 2010	4

Consolidated Statement of Equity – Nine Months Ended September 30, 2011	5

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2011 and 2010	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	39

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54

ITEM 4. CONTROLS AND PROCEDURES	57

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	57

ITEM 1A. RISK FACTORS	57

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	57

ITEM 3. DEFAULTS UPON SENIOR SECURITIES	57

ITEM 4. [RESERVED]

ITEM 5. OTHER INFORMATION	57

ITEM 6. EXHIBITS	58

SIGNATURE	59

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity,” the “Partnership” or “ETE”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “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 our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011, as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on February 28, 2011.

Definitions

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



	/d		per day

	Bbls		barrels

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

	Capacity		capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

	Mcf		thousand cubic feet

	MMBtu		million British thermal units

	MMcf		million cubic feet

	Bcf		billion cubic feet

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

	Tcf		trillion cubic feet

	LIBOR		London Interbank Offered Rate

	NYMEX		New York Mercantile Exchange

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

	WTI		West Texas Intermediate Crude

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)



	September 30, 2011			December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	167,715		$	86,264
Marketable securities	3,151			2,032
Accounts receivable, net of allowance for doubtful accounts of $7,123 and $6,706 as of September 30, 2011 and December 31, 2010, respectively	669,955			612,357
Accounts receivable from related companies	86,454			76,331
Inventories	328,841			366,384
Exchanges receivable	17,675			21,926
Price risk management assets	15,719			16,357
Other current assets	143,578			109,359
Total current assets	1,433,088			1,291,010
PROPERTY, PLANT AND EQUIPMENT	15,922,724			13,284,430
ACCUMULATED DEPRECIATION	(1,822,675		)	(1,431,698		)
	14,100,049			11,852,732
ADVANCES TO AND INVESTMENTS IN AFFILIATES	1,515,604			1,359,979
LONG-TERM PRICE RISK MANAGEMENT ASSETS	23,523			13,971
GOODWILL	2,039,383			1,600,611
INTANGIBLE ASSETS, net	1,083,968			1,034,846
OTHER NON-CURRENT ASSETS, net	247,703			225,581
Total assets	$	20,443,318		$	17,378,730

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)



	September 30, 2011		December 31, 2010
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	468,480	$	421,556
Accounts payable to related companies	24,618		27,351
Exchanges payable	15,758		16,003
Price risk management liabilities	76,615		13,172
Accrued and other current liabilities	794,660		567,688
Current maturities of long-term debt	424,119		35,305
Total current liabilities	1,804,250		1,081,075
LONG-TERM DEBT, less current maturities	11,252,745		9,346,067
SERIES A CONVERTIBLE PREFERRED UNITS (Note 10)	314,980		317,600
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES	73,261		79,465
OTHER NON-CURRENT LIABILITIES	243,473		235,848

COMMITMENTS AND CONTINGENCIES (Note 14)

PREFERRED UNITS OF SUBSIDIARY (Note 10)	71,091		70,943

EQUITY:
General Partner	306		520
Limited Partners:
Common Unitholders	47,483		115,350
Accumulated other comprehensive income	2,736		4,798
Total partners’ capital	50,525		120,668
Noncontrolling interest	6,632,993		6,127,064
Total equity	6,683,518		6,247,732
Total liabilities and equity	$	20,443,318	$	17,378,730

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
REVENUES:
Natural gas operations	$	1,858,656		$	1,380,029		$	5,016,564		$	3,827,506
Retail propane	213,496			183,786			962,258			914,372
Other	25,714			23,992			83,070			80,438
Total revenues	2,097,866			1,587,807			6,061,892			4,822,316
COSTS AND EXPENSES:
Cost of products sold — natural gas operations	1,203,537			883,716			3,210,163			2,520,157
Cost of products sold — retail propane	141,868			104,533			587,460			519,796
Cost of products sold — other	7,632			6,856			20,992			20,470
Operating expenses	234,282			208,809			677,695			559,302
Depreciation and amortization	157,952			120,315			445,738			304,681
Selling, general and administrative	82,587			61,526			225,032			177,673
Total costs and expenses	1,827,858			1,385,755			5,167,080			4,102,079
OPERATING INCOME	270,008			202,052			894,812			720,237
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(193,772		)	(209,871		)	(543,218		)	(460,578		)
Equity in earnings of affiliates	28,374			22,349			82,634			40,723
Losses on non-hedged interest rate derivatives	(68,497		)	(31,966		)	(65,094		)	(68,858		)
Impairment of investments in affiliates	(5,355		)	—			(5,355		)	(52,620		)
Other, net	33,231			14,379			21,081			10,819
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	63,989			(3,057		)	384,860			189,723
Income tax expense	3,290			2,093			18,417			11,357
INCOME (LOSS) FROM CONTINUING OPERATIONS	60,699			(5,150		)	366,443			178,366
Income from discontinued operations	—			324			—			410
NET INCOME (LOSS)	60,699			(4,826		)	366,443			178,776
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST	(8,384		)	10,511			142,435			62,069
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS	69,083			(15,337		)	224,008			116,707
GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)	214			(48		)	693			361
LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)	$	68,869		$	(15,289	)	$	223,315		$	116,346
BASIC NET INCOME (LOSS) PER LIMITED PARTNER UNIT	$	0.31		$	(0.07	)	$	1.00		$	0.52
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING	222,972,708			222,941,172			222,966,763			222,941,151
DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT	$	0.31		$	(0.07	)	$	1.00		$	0.52
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING	222,972,708			222,941,172			222,966,763			222,941,151

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income (loss)	$	60,699		$	(4,826	)	$	366,443		$	178,776
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	288			64,644			(13,129		)	67,199
Change in value of derivative instruments accounted for as cash flow hedges	16,412			25,791			9,403			30,291
Change in value of available-for-sale securities	(900		)	(732		)	(935		)	(3,785		)
	15,800			89,703			(4,661		)	93,705
Comprehensive income	76,499			84,877			361,782			272,481
Less: Comprehensive income attributable to noncontrolling interest	4,323			32,197			139,836			89,915
Comprehensive income attributable to partners	$	72,176		$	52,680		$	221,946		$	182,566

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011

(Dollars in thousands)

(unaudited)



	General Partner			Common Unitholders			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, December 31, 2010	$	520		$	115,350		$	4,798		$	6,127,064		$	6,247,732
Distributions to ETE partners	(1,194		)	(384,612		)	—			—			(385,806		)
Distributions to noncontrolling interest	—			—			—			(574,285		)	(574,285		)
Subsidiary units issued for cash	291			93,650			—			909,268			1,003,209
Subsidiary units issued in acquisition	—			—			—			3,000			3,000
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings	—			846			—			32,328			33,174
Non-cash executive compensation	—			19			—			919			938
Other, net	(4		)	(1,085		)	—			(5,137		)	(6,226		)
Other comprehensive loss, net of tax	—			—			(2,062		)	(2,599		)	(4,661		)
Net income	693			223,315			—			142,435			366,443
Balance, September 30, 2011	$	306		$	47,483		$	2,736		$	6,632,993		$	6,683,518

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)



	Nine Months Ended September 30,
	2011			2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:
Net income	$	366,443		$	178,776
Reconciliation of net income to net cash provided by operating activities:
Impairment of investments in affiliates	5,355			52,620
Payments for termination of Parent Company interest rate derivatives	—			(168,550		)
Proceeds from termination of interest rate derivatives	—			26,495
Depreciation and amortization	445,738			304,681
Amortization of finance costs charged to interest	14,581			13,299
Non-cash unit-based compensation expense	33,491			22,547
Non-cash executive compensation expense	938			938
Losses on disposal of assets	3,272			408
Distributions in excess of equity in earnings of affiliates, net	2,177			71,026
Other non-cash	(3,211		)	(5,361		)
Changes in operating assets and liabilities, net of effects of acquisitions (Note 4)	234,176			430,804
Net cash provided by operating activities	1,102,960			927,683
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(1,971,438		)	(323,705		)
Capital expenditures (excluding allowance for equity funds used during construction)	(1,232,059		)	(1,125,104		)
Contributions in aid of construction costs	18,435			12,048
Advances to affiliates, net	(166,506		)	(44,968		)
Proceeds from the sale of assets	15,570			84,044
Net cash used in investing activities	(3,335,998		)	(1,397,685		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	6,429,107			2,927,042
Principal payments on debt	(4,130,493		)	(3,133,678		)
Subsidiary equity offering, net of issue costs	1,003,209			1,486,863
Distributions to partners	(385,806		)	(362,286		)
Debt issuance costs	(22,217		)	(35,612		)
Distributions to noncontrolling interest	(574,285		)	(390,805		)
Other, net	(5,026		)	(1,724		)
Net cash provided by financing activities	2,314,489			489,800
INCREASE IN CASH AND CASH EQUIVALENTS	81,451			19,798
CASH AND CASH EQUIVALENTS, beginning of period	86,264			68,315
CASH AND CASH EQUIVALENTS, end of period	$	167,715		$	88,113

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)


1.	OPERATIONS AND ORGANIZATION:

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 September 30, 2011, our equity interests consisted of:



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

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

•the Parent Company;


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

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

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

ETE obtained control of Regency on May 26, 2010, and as such, the nine month period ended September 30, 2010 includes the results of Regency for the period from the acquisition date through the end of the period.

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 Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% interest in Lone Star NGL LLC (“Lone Star”), a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. ETP is also one of the largest retail marketers of propane in the United States.

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•

Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating, transportation, fractionation and storage of natural gas and NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, and Marcellus shales, as well as the Permian Delaware basin. Its assets are located in California, Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2010, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership, as of September 30, 2011 and for the three and nine month periods ended September 30, 2011 and 2010, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. Management has evaluated subsequent events through the date the financial statements were issued.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of September 30, 2011, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2011 and 2010. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010, as filed with the SEC on February 28, 2011.

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


2.	ESTIMATES:

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

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

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


3.	ACQUISITIONS AND DIVESTITURES:

LDH Acquisition

On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by ETP and 30% by Regency, acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), from Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”) for approximately $1.98 billion in cash (the “LDH Acquisition”), including working capital adjustments. ETP contributed approximately $1.38 billion to ETP-Regency LLC to fund its 70% share of the purchase price, while Regency contributed approximately $592.7 million to fund its 30% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star.

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

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

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



Total current assets	$	118,177
Property, plant and equipment⁽¹⁾	1,419,591
Goodwill	432,026
Intangible assets	81,000
Other assets	157
	2,050,951

Total current liabilities	74,964
Other long-term liabilities	438
	75,402
Total consideration	1,975,549
Cash received	31,231
Total consideration, net of cash received	$	1,944,318

(1)Property, plant and equipment (and estimated useful lives) consists of the following:



Land and improvements	$	30,759
Buildings and improvements (10 to 40 years)	3,123
Pipelines and equipment (20 to 65 years)	662,881
Natural gas liquids storage (40 years)	682,419
Linepack	704
Vehicles (3 to 20 years)	242
Furniture and fixtures (3 to 10 years)	49
Other (5 to 10 years)	8,526
Construction work-in-process	30,888
Property, plant and equipment	$	1,419,591

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Pro Forma Results of Operations

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
Revenues	$	2,097,866	$	1,656,950		$	6,170,481	$	5,558,813
Net income (loss)	60,669		(10,114		)	358,230		203,747
Net income attributable to partners	69,083		(16,777		)	221,972		162,889
Basic net income (loss) per Limited Partner unit	$	0.31	$	(0.08	)	$	1.00	$	0.73
Diluted net income (loss) per Limited Partner unit	$	0.31	$	(0.08	)	$	1.00	$	0.73

The pro forma consolidated results of operations include adjustments to:

•include the results of LDH and Regency for all periods presented;


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

•include incremental interest expense related to financing the purchase price;

•adjust for one-time expenses; and

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

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

Pending Acquisition

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

Consummation of the SUG Merger is subject to customary conditions, including, without limitation: (i) the adoption of the Second Amended SUG Merger Agreement by the stockholders of SUG, (ii) the receipt of required approvals from the Federal Energy Regulatory Commission (“FERC”), the Missouri Public Service Commission and, if required, the Massachusetts Department of Public Utilities, (iii) the effectiveness of a registration statement on Form S-4 relating to the ETE Common Units to be issued in the SUG Merger, and (iv) the absence of any law, injunction, judgment or ruling prohibiting or restraining the SUG Merger or making the consummation of the SUG Merger illegal. On July 28, 2011, the waiting period applicable to the SUG Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR Act") expired. On September 23, 2011, the FERC issued a letter order authorizing the transfer of FERC-jurisdictional facilities resulting from the SUG Merger. On October 27, 2011, the registration statement on Form S-4 was declared effective by the SEC.

Citrus Transaction

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

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the Amended Citrus Merger Agreement.

Under the Amended Citrus Merger Agreement, it is anticipated that SUG will cause the contribution to ETP of a 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission pipeline system and is currently jointly owned by SUG and El Paso Corporation (the “Citrus Transaction”). The Citrus Transaction will be effected through the merger of Citrus ETP Acquisition, L.L.C., a Delaware limited liability company and wholly-owned subsidiary of SUG that indirectly owns a 50% interest in Citrus Corp. (“CrossCountry”). In exchange for the interest in Citrus Corp., SUG will receive approximately $2 billion, consisting of approximately $1.9 billion in cash and $105 million of ETP Common Units, with the value of the ETP Common Units based on the volume-weighted average trading price for the 10 consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Transaction. In order to increase the expected accretion to be derived from the Citrus Transaction, we have agreed to relinquish our rights to approximately $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the transaction.

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

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

Midcontinent Express Pipeline

In conjunction with the Regency Transactions in May 2010, Regency acquired an indirect 49.9% interest in the Midcontinent Express Pipeline LLC (“MEP”), and an option to acquire an additional 0.1% interest in MEP subsequent to May 2011. On September 1, 2011, Regency exercised its option to acquire the remaining 0.1% interest in MEP from ETP for approximately $1.2 million in cash.

Propane Operations

In October 2011, ETP entered into an agreement with AmeriGas Partners, L.P. (“AmeriGas”) to contribute its propane operations, consisting of Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) (collectively, the “Propane Business”) to AmeriGas in exchange for consideration of approximately $2.9 billion. The consideration consists of $1.5 billion in cash and common units of AmeriGas valued at $1.32 billion at the time of the execution of the agreement, plus the assumption of certain liabilities of the Propane Business. One of ETP's closing deliverables under the agreement is that it enters into and delivers a support agreement with AmeriGas that ETP will provide contingent, residual support of senior notes issued by AmeriGas to finance the cash portion of the purchase price. The transaction is subject to customary closing conditions, including approval under the HSR Act, and is expected to close late 2011 or early 2012.

We have not reflected the Propane operations as discontinued operations as we expect to have a continuing involvement in this business as a result of the investment in AmeriGas that would be transferred to ETP as consideration for the transaction.


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.

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



	Nine Months Ended September 30,
	2011			2010
Accounts receivable	$	15,492		$	200,962
Accounts receivable from related companies	(8,401		)	(10,637		)
Inventories	50,096			113,790
Exchanges receivable	4,251			4,757
Other current assets	(15,992		)	21,250
Other non-current assets, net	7,406			8,538
Accounts payable	(26,696		)	(107,895		)
Accounts payable to related companies	(2,733		)	(5,741		)
Exchanges payable	(244		)	(8,340		)
Accrued and other current liabilities	165,277			52,127
Other non-current liabilities	1,244			(741		)
Price risk management assets and liabilities, net	44,476			162,734
Net change in operating assets and liabilities, net of effects of acquisitions	$	234,176		$	430,804

Non-cash investing and financing activities are as follows:



	Nine Months Ended September 30,
	2011		2010
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	154,378	$	83,834
Gain from subsidiary common unit transactions	$	93,941	$	343,714
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuance of common units in connection with acquisition	$	3,000	$	—
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	4,166	$	1,240,481


5.	INVENTORIES:

Inventories consisted of the following:



	September 30, 2011		December 31, 2010
Natural gas and NGLs, excluding propane	$	120,798	$	170,179
Propane	75,085		76,341
Appliances, parts and fittings and other	132,958		119,864
Total inventories	$	328,841	$	366,384

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

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6.	GOODWILL AND INTANGIBLE ASSETS:

A net increase in goodwill of $438.8 million was recorded during the nine months ended September 30, 2011 primarily due to the LDH Acquisition referenced in Note 3. This additional goodwill is expected to be deductible for tax purposes. In addition, ETP recorded customer contracts of $81 million with useful lives ranging from 3 to 15 years.

Components and useful lives of intangible assets were as follows:



	September 30, 2011					December 31, 2010
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)	$	1,056,948	$	(122,257	)	$	971,657	$	(88,583	)
Trade names (20 years)	65,500		(4,367		)	65,500		(1,910		)
Noncompete agreements (3 to 15 years)	15,893		(7,900		)	21,165		(11,888		)
Patents (9 years)	750		(181		)	750		(118		)
Other (10 to 15 years)	1,320		(566		)	1,320		(492		)
Total amortizable intangible assets	1,140,411		(135,271		)	1,060,392		(102,991		)
Non-amortizable intangible assets:
Trademarks	78,828		—			77,445		—
Total intangible assets	$	1,219,239	$	(135,271	)	$	1,137,837	$	(102,991	)

Aggregate amortization expense of intangible assets was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Reported in depreciation and amortization	$	13,168	$	7,887	$	40,541	$	23,215

Estimated aggregate amortization expense related to intangible assets for the next five years is as follows:



Years Ending December 31:
2012	$	53,989
2013	49,652
2014	48,531
2015	47,644
2016	46,864

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review goodwill and non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage, midstream and retail propane operations and as of December 31 for all others, including all of Regency’s reporting units. We have not completed our annual impairment tests for 2011 and have not recorded any impairments related to amortizable intangible assets during the nine months ended September 30, 2011.

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Recently Issued Accounting Standards

In September 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”), which simplifies how entities test goodwill for impairment. ASU 2011-08 gives entities the option, under certain circumstances, to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. ASU 2011-08 is effective for fiscal years beginning after December 15, 2011, and early adoption is permitted. We are currently evaluating early adoption of ASU 2011-08, but we do not expect adoption of this standard will materially impact our financial position or results of operations.


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 September 30, 2011 was $12.27 billion and $11.68 billion, respectively. As of December 31, 2010, the aggregate fair value and carrying amount of our consolidated debt obligations was $10.23 billion and $9.38 billion, respectively.

We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Preferred Units of a Subsidiary (the “Regency Preferred Units”) that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.

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



	Fair Value Measurements at September 30, 2011 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	3,151		$	3,151		$	—		$	—
Interest rate derivatives	30,564			—			30,564			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	74,892			74,892			—			—
Swing Swaps IFERC	21,818			1,074			20,744			—
Fixed Swaps/Futures	73,076			70,112			2,964			—
Options — Puts	13,348			—			13,348			—
Forward Physical Swaps	738			—			738			—
NGLs — Forward Swaps	577			—			577			—
Propane — Forward Swaps	77			—			77			—
WTI Crude Oil	4,817			—			4,817			—
Total commodity derivatives	189,343			146,078			43,265			—
Total Assets	$	223,058		$	149,229		$	73,829		$	—
Liabilities:
Interest rate derivatives	$	(99,658	)	$	—		$	(99,658	)	$	—
Series A Convertible Preferred Units	(314,980		)	—			—			(314,980		)
Embedded derivatives in the Regency Preferred Units	(36,268		)	—			—			(36,268		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(68,918		)	(68,918		)	—			—
Swing Swaps IFERC	(22,707		)	(1,988		)	(20,719		)	—
Fixed Swaps/Futures	(48,287		)	(48,133		)	(154		)	—
Options — Puts	(423		)	—			(423		)	—
Options — Calls	(122		)	—			(122		)	—
Forward Physical Swaps	(482		)	—			(482		)	—
NGLs — Forward Swaps	(11,722		)	—			(11,722		)	—
Propane — Forward Swaps	(2,086		)	—			(2,086		)	—
Total commodity derivatives	(154,747		)	(119,039		)	(35,708		)	—
Total Liabilities	$	(605,653	)	$	(119,039	)	$	(135,366	)	$	(351,248	)

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	Fair Value Measurements at December 31, 2010 Using
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Marketable securities	$	2,032		$	2,032		$	—		$	—
Interest rate derivatives	20,790			—			20,790			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	15,756			15,756			—			—
Swing Swaps IFERC	1,682			1,562			120			—
Fixed Swaps/Futures	44,955			42,474			2,481			—
Options — Calls	75			—			75			—
Options — Puts	26,241			—			26,241			—
NGLs — Forward Swaps	192			—			192			—
Propane — Forward Swaps	6,864			—			6,864			—
Total commodity derivatives	95,765			59,792			35,973			—
Total Assets	$	118,587		$	61,824		$	56,763		$	—
Liabilities:
Interest rate derivatives	$	(20,922	)	$	—		$	(20,922	)	$	—
Series A Convertible Preferred Units	(317,600		)	—			—			(317,600		)
Embedded derivatives in the Regency Preferred Units	(57,023		)	—			—			(57,023		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(17,372		)	(17,372		)	—			—
Swing Swaps IFERC	(3,768		)	(3,520		)	(248		)	—
Fixed Swaps/Futures	(42,252		)	(41,825		)	(427		)	—
Options — Calls	(2,643		)	—			(2,643		)	—
Options — Puts	(7		)	—			(7		)	—
NGLs — Forward Swaps	(10,684		)	—			(10,684		)	—
WTI Crude Oil	(3,581		)	—			(3,581		)	—
Total commodity derivatives	(80,307		)	(62,717		)	(17,590		)	—
Total Liabilities	$	(475,852	)	$	(62,717	)	$	(38,512	)	$	(374,623	)

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



Balance, December 31, 2010	$	(374,623	)
Net unrealized gains included in other income (expense)	23,375
Balance, September 30, 2011	$	(351,248	)

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8.	NET INCOME (LOSS) PER LIMITED PARTNER UNIT:

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
Basic Net Income (Loss) per Limited Partner Unit:
Limited Partners’ interest in net income (loss)	$	68,869	$	(15,289	)	$	223,315	$	116,346
Weighted average Limited Partner units	222,972,708		222,941,172			222,966,763		222,941,151
Basic net income (loss) per Limited Partner unit	$	0.31	$	(0.07	)	$	1.00	$	0.52
Diluted Net Income (Loss) per Limited Partner Unit:
Limited Partners’ interest in net income (loss)	$	68,869	$	(15,289	)	$	223,315	$	116,346
Dilutive effect of equity-based compensation of subsidiaries	167		—			525		158
Diluted net income (loss) available to Limited Partners	$	68,702	$	(15,289	)	$	222,790	$	116,188
Weighted average Limited Partner units	222,972,708		222,941,172			222,966,763		222,941,151
Diluted net income (loss) per Limited Partner unit	$	0.31	$	(0.07	)	$	1.00	$	0.52

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

The calculation above for the three and nine months ended September 30, 2011 for diluted net income (loss) per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units have a liquidation preference of $300 million and are subject to mandatory conversion as discussed in Note 10.


9.	DEBT OBLIGATIONS:

Senior Notes

ETP Senior Notes

In May 2011, ETP completed a public offering of $800 million aggregate principal amount of 4.65% Senior Notes due June 1, 2021 and $700 million aggregate principal amount of 6.05% Senior Notes due June 1, 2041. ETP used the proceeds, net of commissions, of $1.48 billion to repay all of the borrowings outstanding under its revolving credit facility (the “ETP Credit Facility”), to fund capital expenditures related to pipeline construction projects and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.

Regency Senior Notes

In May 2011, Regency issued $500 million aggregate principal amount of 6.50% Senior Notes due July 15, 2021 (the “Regency 2021 Notes”). Regency used the proceeds, net of commissions, of approximately $491.3 million to repay borrowings outstanding under its revolving credit facility (the “Regency Credit Facility”). Regency capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the Regency 2021 Notes. Interest will be paid semi-annually.

At any time prior to July 15, 2016, Regency may redeem some or all of the Regency 2021 Notes at a redemption price equal to 100% of the principal amount plus a “make-whole” premium, plus accrued and unpaid interest to the redemption date. At any time before July 15, 2014, Regency may redeem up to 35% of the aggregate principal amount of the Regency 2021 Notes then outstanding at a redemption price equal to 106.5% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the redemption date.

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

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


•	incur additional indebtedness;


•	pay distributions on, or repurchase or redeem equity interests;


•	make certain investments;


•	incur liens;


•	enter into certain types of transactions with affiliates; and


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

Revolving Credit Facilities

Parent Company Credit Agreement

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

ETP Credit Facility

The ETP Credit Facility provides for $2 billion of revolving credit capacity that is expandable to $3 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity). The ETP Credit Facility matures on July 20, 2012, unless ETP elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). As of September 30, 2011, ETP had a balance of $574.6 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.4 billion taking into account letters of credit of $24.3 million. The weighted average interest rate on the total amount outstanding as of September 30, 2011 was 0.80%.

On October 27, 2011, ETP amended and restated the ETP Credit Facility to, among other things, (i) allow for borrowings of up to $2.5 billion; (ii) extend the maturity date from July 20, 2012 to October 27, 2016 (which may be extended by one year with lender approval); (iii) allow for an increase in the size of the credit facility to $3.75 billion (subject to obtaining lender commitments for the additional borrowing capacity); and (iv) to adjust the interest rates and commitment fees to current market terms. Following this amendment and based on ETP's current ratings, the interest margin for LIBOR rate loans is 1.50% and the commitment fee for unused borrowing capacity is 0.25%.

Regency Credit Facility

The Regency Credit Facility has aggregate revolving commitments of $900 million that matures June 15, 2014. As of September 30, 2011, there was a balance outstanding under the Regency Credit Facility of $445 million in revolving credit loans and approximately $20 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2011, which is reduced by any letters of credit, was approximately $435 million. The weighted average interest rate on the total amount outstanding as of September 30, 2011 was 3.03%.

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 September 30, 2011.

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10.	REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

In connection with the Regency Transactions completed in May 2010, ETE issued 3,000,000 Series A Convertible Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300 million. These units are reflected as a non-current liability in our consolidated balance sheets as of September 30, 2011 and December 31, 2010. The Preferred Units are measured at fair value on a recurring basis. Changes in the estimated fair value of the ETE Preferred Units are recorded in other income (expense) on the consolidated statements of operations.

Regency Preferred Units

Regency has 4,371,586 Regency Preferred Units outstanding at September 30, 2011, which were convertible into 4,626,197 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.


11.	EQUITY:

ETE Common Units Issued

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



	Number of Units
Outstanding at December 31, 2010	222,941,172
Issuance of restricted common units under equity incentive plan	31,536
Outstanding at September 30, 2011	222,972,708

Sales of Common Units by Subsidiaries

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

As a result of ETP’s and Regency’s issuances of Common Units during the nine months ended September 30, 2011, we recognized increases in partners’ capital of $93.9 million.

Sales of Common Units by ETP

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

ETP has an Equity Distribution Agreement with Credit Suisse Securities (USA) LLC (“Credit Suisse”) under which ETP may offer and sell from time to time through Credit Suisse, as its sales agent, ETP Common Units having an aggregate offering price of up to $200 million. During the nine months ended September 30, 2011, ETP received proceeds from units issued pursuant to this agreement of approximately $96.3 million, net of commissions, which were used for general partnership purposes. Approximately $77.5 million of ETP Common Units remain available to be issued under the Equity Distribution Agreement based on trades initiated through September 30, 2011.

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

For the nine months ended September 30, 2011, distributions of approximately $7.6 million were reinvested under the DRIP resulting in the issuance of 175,863 Common Units.

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Sales of Common Units by Regency

In October 2011, Regency issued 11,500,000 Regency Common Units through a public offering. The proceeds, net of commissions, of approximately $231.9 million were used to repay borrowings outstanding under the Regency Credit Facility.

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

Parent Company Quarterly Distributions of Available Cash

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

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



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 18, 2011	$	0.540
March 31, 2011	May 6, 2011	May 19, 2011	0.560
June 30, 2011	August 5, 2011	August 19, 2011	0.625
September 30, 2011	November 4, 2011	November 18, 2011	0.625

ETP Quarterly Distributions of Available Cash

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



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 14, 2011	$	0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375
September 30, 2011	November 4, 2011	November 14, 2011	0.89375

Regency Quarterly Distributions of Available Cash

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



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	0.445
June 30, 2011	August 5, 2011	August 12, 2011	0.450
September 30, 2011	November 7, 2011	November 14, 2011	0.455

Accumulated Other Comprehensive Income

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



	September 30, 2011			December 31, 2010
Net gains on commodity related hedges	$	10,420		$	14,146
Unrealized gains (losses) on available-for-sale securities	(17		)	918
Subtotal	10,403			15,064
Amounts attributable to noncontrolling interest	(7,667		)	(10,266		)
Total AOCI included in partners’ capital, net of tax	$	2,736		$	4,798

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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 nine months ended September 30, 2011, ETE employees were granted a total of 30,000 unvested awards with five-year service vesting requirements. The weighted average grant-date fair value of these awards was $39.82 per unit. As of September 30, 2011 a total of 105,713 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $1.4 million in compensation expense over a weighted average period of 1.9 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the nine months ended September 30, 2011, ETP employees were granted a total of 556,700 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 $53.12 per unit. As of September 30, 2011 a total of 2,349,540 unit awards remain unvested, including the new awards granted during the period. ETP expects to recognize a total of $58.3 million in compensation expense over a weighted average period of 1.7 years related to unvested awards.

Regency Unit-Based Compensation Plans

Common Unit Options

During the nine months ended September 30, 2011, no Regency Common Unit options were granted. As of September 30, 2011, a total of 156,850 Regency Common Unit options remain vested and exercisable, with a weighted average exercise price of $21.99 per Regency Common Unit option.

Phantom Units

During the nine months ended September 30, 2011, Regency employees and directors were granted 76,745 Regency phantom units with three-year service vesting requirements. As of September 30, 2011, a total of 713,225 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.78. Regency expects to recognize a total of $12 million in compensation expense over a weighted average period of 4.0 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Current expense (benefit):
Federal	$	1,124		$	(3,182	)	$	6,787		$	(124	)
State	2,675			1,363			12,109			8,864
Total	3,799			(1,819		)	18,896			8,740
Deferred expense (benefit):
Federal	(41		)	3,286			(599		)	2,257
State	(468		)	626			120			360
Total	(509		)	3,912			(479		)	2,617
Total income tax expense	$	3,290		$	2,093		$	18,417		$	11,357

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.

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

Regulatory Matter

On September 29, 2006, the Transwestern Pipeline Company, LLC ("Transwestern") filed revised tariff sheets under Section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006. In April 2007, the FERC approved a Stipulation and Agreement of Settlement that resolved the primary components of the rate case. Under the terms of the settlement, Transwestern was required to file a new general NGA Section 4 rate case no later than October 1, 2011. However, Transwestern sought and on September 2, 2011 was granted an extension of the filing date until December 1, 2011 to allow time for settlement discussions with shippers. On September 21, 2011, Transwestern filed a proposed settlement with the FERC, which was approved by the FERC on October 31, 2011. The settlement maintains the currently effective transportation and fuel tariff rates with the exception that it reduces certain San Juan Lateral fuel rates staggered over the three year period beginning in April 2012. The settlement also resolves certain non-rate matters and reflects a continuation of the accounting practices from the prior rate settlement. Under the settlement, Transwestern will be required to file a Section 4 rate case on October 1, 2014.

Guarantee — Fayetteville Express Pipeline LLC

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

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

NGL Pipeline Regulation

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

Commitments

In the normal course of our business, ETP and Regency purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP has also entered into several propane purchase and supply commitments, which are typically one year agreements with varying terms as to quantities, prices and expiration dates. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

ETP and Regency have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $7.3 million and $6 million for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, rental expense for operating leases totaled approximately $20.5 million and $17.7 million, respectively.

ETP’s propane operations have an agreement with Enterprise Products Partners L.P. (together with its subsidiaries “Enterprise”) (see Note 16) to supply a portion of its propane requirements. The agreement will continue until 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 million gallons per year through 2015 at market prices plus a nominal fee.

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

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and propane are flammable, combustible gases. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2011 and December 31, 2010, accruals of approximately $13.3 million and $10.2 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty, and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Further, we may revise accrual amounts prior to the resolution of a particular contingency based on changes in facts and circumstances or in the expected outcome.

No amounts have been recorded in our September 30, 2011 or December 31, 2010 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities.

We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

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

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we

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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

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

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of 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 September 30, 2011 and December 31, 2010, accruals related to ETP on an undiscounted basis of $12.6 million and $13.8 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.

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

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”). The costs of this work are not eligible for recovery in rates. ETP’s total accrued future estimated cost of remediation activities expected to continue through 2025 is $7.9 million, which is included in the aggregate environmental accruals discussed above. Transwestern received approval from the FERC for the continuation of rate recovery of projected soil and groundwater remediation costs not related to PCBs for the term of its rate case settlement.

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 expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but 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, and ETP believes that its operations have not contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our September 30, 2011 or December 31, 2010 consolidated balance sheets. Based on information currently available to us, the presence of contamination and remediation activities at these sites 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 federal Clean Air Act ("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. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for

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Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, ETP would not expect that the cost to comply with the rule's requirements will have a material adverse effect on its financial condition or results of operations. Compliance with the final rule is required by October 2013.

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

ETP’s pipeline operations are subject to regulation by the DOT under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. For the three months ended September 30, 2011 and 2010, $4.2 million and $5.8 million, respectively, of capital costs and $3.9 million of operating and maintenance costs have been incurred for pipeline integrity testing. For the nine months ended September 30, 2011 and 2010, $9.7 million and $10.8 million, respectively, of capital costs and $9.8 million and $10.2 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines; however, no estimate can be made at this time of the likely range of such expenditures.


15.	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by segment as well as tables detailing the outstanding commodity-related derivatives as of September 30, 2011 and December 31, 2010 by segment.

Investment in ETP

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

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

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

ETP’s propane operations permit customers to guarantee the propane delivery price for the next heating season. As ETP executes fixed sales price contracts with its customers, it may enter into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin. Additionally, ETP may use propane futures contracts to secure the purchase price of its propane inventory for a percentage of its anticipated propane sales.

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



	September 30, 2011			December 31, 2010
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)	(39,952,500	)	2011-2013	(38,897,500	)	2011
Swing Swaps IFERC (MMBtu)	30,517,500		2011-2013	(19,720,000	)	2011
Fixed Swaps/Futures (MMBtu)	(15,517,500	)	2011-2012	(2,570,000	)	2011
Forward Physical Contracts (MMBtu)	12,324,054		2011-2012	—		—
Options — Calls (MMBtu)	—		—	(3,000,000	)	2011
Propane:
Forwards/Swaps (Gallons)	52,668,000		2011-2012	1,974,000		2011
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)	(19,685,000	)	2011-2012	(28,050,000	)	2011
Fixed Swaps/Futures (MMBtu)	(29,837,500	)	2011-2012	(39,105,000	)	2011
Hedged Item — Inventory (MMBtu)	29,837,500		2011	39,105,000		2011
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)	460,000		2011	(210,000	)	2011
Options — Puts (MMBtu)	9,390,000		2011-2012	26,760,000		2011-2012
Options — Calls (MMBtu)	(9,390,000	)	2011-2012	(26,760,000	)	2011-2012
Propane:
Forwards/Swaps (Gallons)	—		—	32,466,000		2011

We expect gains of $11.6 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

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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:



	September 30, 2011		December 31, 2010
	Notional Volume	Maturity	Notional Volume	Maturity
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures (MMBtu)	2,934,000	2012	3,830,000	2011
Propane:
Forwards/Swaps (Gallons)	15,204,000	2013	18,648,000	2011-2012
Natural Gas Liquids:
Forwards/Swaps (Barrels)	771,000	2013	1,212,110	2011-2012
WTI Crude Oil:
Forwards/Swaps (Barrels)	417,000	2014	373,655	2011-2012

We expect losses of $5.3 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.

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Interest Rate Risk

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. The following is a summary of interest rate swaps outstanding as of September 30, 2011 and December 31, 2010, none of which were designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

September 30, 2011

December 31, 2010

ETP

May 2012 ⁽²⁾

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

350,000

—

ETP

August 2012⁽²⁾

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

500,000

400,000

ETP

July 2013 ⁽²⁾

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

300,000

—

ETP

July 2018

Pay a floating rate plus a spread of 4.01% 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)As of September 30, 2011. Floating rates are based on 3-month LIBOR.


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

Credit Risk

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

Our counterparties consist primarily of petrochemical companies, other industrial, mid-size to major oil and gas companies and power companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty performance.

ETP utilizes master netting agreements and has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in our consolidated balance sheets. ETP had net deposits with counterparties of $56.4 million and $52.2 million as of September 30, 2011 and December 31, 2010, respectively.

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

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

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Derivative Summary

The following table provides a balance sheet overview of consolidated derivative assets and liabilities as of September 30, 2011 and December 31, 2010:



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2011		December 31, 2010		September 30, 2011			December 31, 2010
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	43,337	$	35,031	$	(461	)	$	(6,631	)
Commodity derivatives	8,358		9,263		(11,876		)	(14,692		)
	51,695		44,294		(12,337		)	(21,323		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	146,589	$	64,940	$	(149,598	)	$	(72,729	)
Commodity derivatives	815		275		(2,568		)	—
Interest rate derivatives	30,564		20,790		(99,658		)	(20,922		)
Embedded derivatives in Regency Preferred Units	—		—		(36,268		)	(57,023		)
	177,968		86,005		(288,092		)	(150,674		)
Total derivatives	$	229,663	$	130,299	$	(300,429	)	$	(171,997	)

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

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

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



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	16,414	$	36,035		$	9,291	$	60,992
Interest rate derivatives	—		(9,825		)	—		(29,980		)
Total	$	16,414	$	26,210		$	9,291	$	31,012

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	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended September 30,						Nine Months Ended September 30,
		2011			2010			2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(166	)	$	6,780		$	12,793	$	19,153
Interest rate derivatives	Interest expense, net	—			(70,812		)	—		(86,697		)
Total		$	(166	)	$	(64,032	)	$	12,793	$	(67,544	)



	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
		Three Months Ended September 30,					Nine Months Ended September 30,
		2011			2010		2011		2010
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(91	)	$	241	$	98	$	346
Total		$	(91	)	$	241	$	98	$	346



	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 September 30,					Nine Months Ended September 30,
		2011			2010		2011		2010
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(3,559	)	$	9,968	$	18,732	$	9,001
Total		$	(3,559	)	$	9,968	$	18,732	$	9,001



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
Derivatives not designated as hedging instruments:
Commodity derivatives	Cost of products sold	$	9,056		$	3,219		$	4,067		$	3,762
Interest rate derivatives	Losses on non-hedged interest rate derivatives	(68,496		)	(31,966		)	(65,093		)	(68,858		)
Embedded Derivatives	Other income (expenses)	15,230			7,321			20,755			3,715
Total		$	(44,210	)	$	(21,426	)	$	(40,271	)	$	(61,381	)

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We recognized $0.7 million of unrealized gains and $0.8 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 September 30, 2011 and 2010, respectively. We recognized $2.8 million of unrealized gains and $49 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 nine months ended September 30, 2011 and 2010, respectively. In addition, for the three months ended September 30, 2011 and 2010, we recognized unrealized losses of $7.1 million and unrealized gains of $8.2 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges. For the nine months ended September 30, 2011 and 2010, we recognized unrealized losses of $1.3 million and $35.3 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges.


16.	RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. For the three and nine months ended September 30, 2011, the Parent Company received $4.2 million and $12.4 million in management fees, respectively, from Regency related to these services, while for the three and nine months ended September 30, 2010, the Parent Company received $2.5 million and $3.3 million in management fees, respectively, from Regency related to these services. For the three and nine months ended September 30, 2011, the Parent Company paid $4.4 million and $12.7 million in management fees, respectively, to ETP related to these services, while for the three and nine months ended September 30, 2010, the Parent Company paid $2.6 million and $3.7 million in management fees, respectively, to ETP related to these services. The management fees received from Regency for the three and nine months ended September 30, 2011 reflect the reimbursement of various general and administrative services of $1.7 million and $4.9 million, respectively, for expenses incurred by ETP on behalf of Regency.

Enterprise and its subsidiaries currently hold a significant 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 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 September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
ETP’s Natural Gas Operations:
Sales	$	164,339	$	126,992	$	462,359	$	402,238
Purchases	3,938		396		21,898		13,928
Regency’s Natural Gas Operations:
Sales	119,519		53,620		275,488		72,121
Purchases	2,094		1,890		5,092		2,312
ETP’s Propane Operations:
Sales	395		262		10,613		11,228
Purchases	86,673		58,642		328,830		276,821

As of September 30, 2011 and December 31, 2010, a subsidiary of ETP had forward mark-to-market derivatives for 52.7 million and 1.7 million gallons of propane at a fair value liability of $2.0 million and a fair value asset of $0.2 million, respectively, with Enterprise. In addition, as of December 31, 2010, a subsidiary of ETP had forward derivatives accounted for as cash flow hedges of 32.5 million gallons of propane at a fair value asset of $6.6 million with Enterprise. ETP's propane operations discontinued cash flow hedge accounting during the three months ended September 30, 2011; therefore, all of its forward derivatives are currently accounted for using mark-to-market accounting.

Under a master services agreement with RIGS Haynesville Partnership Co. (“HPC”), Regency operates and provides all employees and services for the operation and management of HPC. The related party general administrative expenses reimbursed to Regency were $4.2 million and $12.6 million for the three and nine months ended September 30, 2011. For

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the three months ended September 30, 2010 and the period from May 26, 2010 to September 30, 2010, the related party general administrative expenses reimbursed to Regency were $4.2 million and $5.6 million, respectively.

Regency’s contract compression operations provide contract compression services to HPC. HPC also provides transportation service to Regency. For the three and nine months ended September 30, 2011, Regency had revenue of $6.4 million and $19.4 million, respectively, and cost of sales of $2.9 million and $11 million, respectively, with HPC. For the three months ended September 30, 2010 and the period from May 26, 2010 to September 30, 2010, Regency had revenue of $5.6 million and $7.7 million, respectively, and cost of sales of $2.5 million and $4.3 million, respectively, with HPC.

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



	September 30, 2011			December 31, 2010
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	53,016		$	36,736
Regency’s Natural Gas Operations	31,285			25,539
ETP’s Propane Operations	222			2,327
Other	1,931			11,729
Total accounts receivable from related parties:	$	86,454		$	76,331
Accounts payable to related parties:
Enterprise:
ETP’s Natural Gas Operations	$	2,465		$	2,687
Regency’s Natural Gas Operations	1,199			1,323
ETP’s Propane Operations	19,632			22,985
Other	1,322			356
Total accounts payable to related parties:	$	24,618		$	27,351

ETP’s net imbalance (payable to) receivable from Enterprise	$	(89	)	$	1,360

Regency’s net imbalance receivable from Enterprise	$	1,464		$	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:



	September 30, 2011		December 31, 2010
Deposits paid to vendors	$	56,435	$	52,192
Prepaid expenses and other	87,143		57,167
Total other current assets	$	143,578	$	109,359

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Other Non-Current Assets, net

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



	September 30, 2011		December 31, 2010
Unamortized financing costs (3 to 30 years)	$	129,921	$	98,067
Regulatory assets	89,943		92,939
Other	27,839		34,575
Total non-current other assets, net	$	247,703	$	225,581

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	September 30, 2011		December 31, 2010
Interest payable	$	247,600	$	191,466
Customer advances and deposits	126,066		111,448
Accrued capital expenditures	147,795		87,260
Accrued wages and benefits	72,117		76,592
Taxes payable other than income taxes	96,007		36,204
Income taxes payable	6,166		8,344
Other	98,909		56,374
Total accrued and other current liabilities	$	794,660	$	567,688


18.	REPORTABLE SEGMENTS:

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

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

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

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

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

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

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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 September 30, 2011:
Revenues from external customers	$	1,708,413	$	388,271		$	—		$	1,182		$	2,097,866
Intersegment revenues	6,903		1,996			—			(8,899		)	—
Income tax expense (benefit)	4,039		(89		)	(660		)	—			3,290
Net income (loss)	76,050		30,849			(36,915		)	(9,285		)	60,699
Three months ended September 30, 2010:
Revenues from external customers	$	1,290,644	$	295,094		$	—		$	2,069		$	1,587,807
Intersegment revenues	—		1,794			—			(1,794		)	—
Income tax expense (benefit)	1,993		450			(350		)	—			2,093
Net income (loss)	107,387		7,846			(120,059		)	—			(4,826		)
Nine months ended September 30, 2011:
Revenues from external customers	$	5,001,208	$	1,058,646		$	—		$	2,038		$	6,061,892
Intersegment revenues	29,780		5,371			—			(35,151		)	—
Income tax expense (benefit)	20,419		(19		)	(1,983		)	—			18,417
Net income (loss)	479,868		59,991			(155,743		)	(17,673		)	366,443
Nine months ended September 30, 2010:
Revenues from external customers	$	4,430,331	$	391,177		$	—		$	808		$	4,822,316
Intersegment revenues	—		2,691			—			(2,691		)	—
Income tax expense (benefit)	12,486		695			(1,824		)	—			11,357
Net income (loss)	390,341		2,951			(214,516		)	—			178,776



	September 30, 2011			December 31, 2010
Total assets:
Investment in ETP	$	15,078,048		$	12,149,992
Investment in Regency	5,525,739			4,770,204
Corporate and Other	480,342			469,221
Adjustments and Eliminations	(640,811		)	(10,687		)
Total	$	20,443,318		$	17,378,730

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

Investment in ETP



	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Intrastate Transportation and Storage	$	617,244	$	529,507	$	1,849,575	$	1,662,037
Interstate Transportation	120,065		74,659		330,016		213,007
Midstream	565,246		458,381		1,492,025		1,484,211
NGL Transportation and Services	131,284		—		224,970		—
Retail Propane and Other Retail Propane Related	236,781		205,833		1,037,969		987,114
All Other	44,696		22,264		96,433		83,962
Total revenues	$	1,715,316	$	1,290,644	$	5,030,988	$	4,430,331

Investment in Regency



	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Gathering and Processing	$	339,273	$	253,054	$	908,448	$	775,636
Joint Ventures	—		—		—		—
Contract Compression	36,024		36,172		112,532		107,197
Contract Treating	10,573		3,299		29,848		3,299
Corporate and Others	4,397		4,363		13,189		12,786
Total revenues	$	390,267	$	296,888	$	1,064,017	$	898,918

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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)



	September 30, 2011		December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	26,174	$	27,247
Accounts receivable from related companies	1,553		171
Other current assets	1,534		864
Total current assets	29,261		28,282
ADVANCES TO AND INVESTMENTS IN AFFILIATES	2,197,813		2,231,722
OTHER NON-CURRENT ASSETS, net	50,720		29,118
Total assets	$	2,277,794	$	2,289,122
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	502	$	—
Accounts payable to related companies	11,469		6,654
Accrued and other current liabilities	100,318		44,200
Total current liabilities	112,289		50,854
LONG-TERM DEBT, less current maturities	1,800,000		1,800,000
SERIES A CONVERTIBLE PREFERRED UNITS	314,980		317,600

COMMITMENTS AND CONTINGENCIES

EQUITY:
General Partner	306		520
Limited Partners	47,483		115,350
Accumulated other comprehensive income	2,736		4,798
Total partners’ capital	50,525		120,668
Total liabilities and equity	$	2,277,794	$	2,289,122

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(11,667	)	$	(2,920	)	$	(25,546	)	$	(20,335	)
OTHER INCOME (EXPENSE):
Interest expense	(40,819		)	(89,484		)	(122,345		)	(126,400		)
Equity in earnings of affiliates	102,565			102,388			369,833			324,128
Losses on non-hedged interest rate derivatives	—			(18,211		)	—			(53,388		)
Other, net	19,068			(6,736		)	2,256			(6,949		)
INCOME (LOSS) BEFORE INCOME TAXES	69,147			(14,963		)	224,198			117,056
Income tax expense	64			374			190			349
NET INCOME (LOSS)	69,083			(15,337		)	224,008			116,707
GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)	214			(48		)	693			361
LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)	$	68,869		$	(15,289	)	$	223,315		$	116,346

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STATEMENTS OF CASH FLOWS

(unaudited)



	Nine Months Ended September 30,
	2011			2010
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	384,733		$	175,126
CASH FLOWS FROM INVESTING ACTIVITIES:
MEP Transaction	—			3,016
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	20,000			1,850,245
Principal payments on debt	(20,000		)	(1,624,374		)
Distributions to partners	(385,806		)	(362,286		)
Debt issuance costs	—			(35,464		)
Net cash used in financing activities	(385,806		)	(171,879		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1,073		)	6,263
CASH AND CASH EQUIVALENTS, beginning of period	27,247			62
CASH AND CASH EQUIVALENTS, end of period	$	26,174		$	6,325

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

AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in thousands)

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC on February 28, 2011. Additionally, Energy Transfer Partners, L.P. and Regency Energy Partners LP electronically file certain documents with the SEC, including annual reports on Form 10-K and quarterly reports on Form 10-Q. The SEC file number for each registrant and company website address is as follows:


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


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

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

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I — Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2010 and in “Part II — Other Information – Item 1A. Risk Factors” of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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 September 30, 2011, our equity interests consisted of:



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

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

The following is a brief description of our reportable segments:

•

Investment in ETP – ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Arkansas, Colorado, Louisiana, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and storage facilities located in Texas. ETP also holds a 70% interest in Lone Star NGL LLC (“Lone Star”), a joint venture that owns and operates NGL storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. ETP is also one of the largest retail marketers of propane in the United States.


•	Investment in Regency – Regency is a publicly traded partnership engaged in the gathering and processing, contract compression, treating, transportation, fractionation and storage of natural gas and NGLs. Regency focuses on providing

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midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, and Marcellus shales, as well as the Permian Delaware basin. Its assets are located in California, Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in Lone Star.

Recent Developments

Pending Acquisition

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

As described in more detail below under the caption “Liquidity and Capital Resources — Overview — Parent Company Only,” we have secured $3.7 billion in committed financing from a group of lenders led by Credit Suisse Securities (USA) LLC (the “Bridge Lenders”) to fund a portion of the cash consideration related to the SUG Merger. Closing of this business combination is contingent upon several conditions, including regulatory approvals and a vote of SUG shareholders. We expect the transaction to close in the first quarter of 2012.

On July 19, 2011, ETP entered into an Amended Citrus Merger Agreement pursuant to which it is anticipated that SUG will cause the contribution to ETP of SUG’s 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission (“FGT”) pipeline system, in exchange for approximately $1.9 billion in cash and $105 million of ETP Common Units, contemporaneous with the completion of the merger between SUG and us pursuant to the Second Amended SUG Merger Agreement as described in Note 3 to our consolidated financial statements. Citrus Corp is currently jointly owned by SUG and El Paso Corporation. The FGT pipeline system has a capacity of 3.0 billion cubic feet per day and supplied approximately 63% of the natural gas consumed in Florida for 2010. FGT’s primary customers are utilities with strong investment grade credit ratings. FGT’s long-term contracts with these high credit quality customers are expected to increase ETP’s fee-based revenue stream.

We expect to incur additional general and administrative costs in connection with consummation of this merger.

Propane Operations

In October 2011, ETP entered into an agreement with AmeriGas Partners, L.P. (“AmeriGas”) to contribute its propane operations, consisting of Heritage Operating, L.P. (“HOLP”) and Titan Energy Partners, L.P. (“Titan”) (collectively, the “Propane Business”) in exchange for consideration of approximately $2.9 billion. The consideration consists of $1.5 billion in cash and common units of AmeriGas valued at $1.32 billion at the time of the execution of the agreement, plus the assumption of certain liabilities of the Propane Business. The transaction is subject to customary closing conditions including regulatory approval and is expected to close in late 2011 or early 2012.

Natural Gas Pipeline and Processing Plant

In October 2011, ETP announced a long-term, fee based agreement with XTO Energy, a subsidiary of ExxonMobil, to provide natural gas gathering, processing and transportation services from the Woodford and Barnett Shale regions. ETP will construct a 117-mile, 24-inch and 30-inch natural gas gathering pipeline from the Woodford Shale to its existing gathering and processing infrastructure in the Barnett Shale. The pipeline will have an initial capacity of 450 MMcf/d, with anticipated capacity expansion exceeding 550 MMcf/d. The pipeline is expected to be in service by the fourth quarter of 2012. As a part of the project, ETP will also construct a new 200 MMcf/d cryogenic processing plant at its existing Godley processing facility in Johnson County, Texas. The new processing plant will increase ETP's processing capacity at its Godley plant from 500 MMcf/d to 700 MMcf/d and is expected to be in service by the third quarter of 2013. The total cost to build the pipeline and processing plant is estimated to be approximately $360 million.

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Tiger Pipeline Expansion

ETP recently completed construction of the 400 MMcf/d expansion of its Tiger pipeline. The Tiger pipeline expansion was placed in service on August 1, 2011, bringing the total capacity of the Tiger pipeline to 2.4 Bcf/d. ETP also began collecting demand fees from the customer who took this capacity over a 10 year term. We are currently collecting demand fees on 1.9 Bcf/d of the Tiger pipeline capacity and are scheduled to begin collecting demand fees on the entire 2.4 Bcf/d of capacity beginning on January 1, 2012.

Lone Star

Lone Star announced the construction of an approximate 570-mile NGL pipeline (“West Texas Gateway Pipeline”) that extends from Winkler County in West Texas to ETP's processing plant in Jackson County, Texas which is currently under construction. In addition, Lone Star has secured capacity on ETP's recently-announced NGL pipeline from Jackson County to Mont Belvieu, Texas. The project is expected to be completed in the first quarter of 2013 for an estimated cost of $917 million, which will be funded by contributions from ETP and Regency based on their respective ownership interests.

Joint Venture

In April 2011, ETP and Enterprise Products Partners L.P. (together with its subsidiaries “Enterprise”) announced that they had agreed to form a 50/50 joint venture to design and construct a crude oil pipeline from Cushing, Oklahoma to Houston, Texas. In August 2011, Enterprise sent ETP a notice stating that Enterprise was purportedly unilaterally terminating the joint venture and Enterprise unilaterally issued a press release that the joint venture was terminated, against the objection of ETP and in breach of the confidentiality agreement between the parties. Enterprise subsequently announced in breach of the joint venture agreement that it and Enbridge Energy Partners, L.P. (“Enbridge”) had formed a joint venture to pursue a similar crude oil pipeline project from Cushing Oklahoma to Houston, Texas. ETP has initiated legal proceedings against Enterprise based on ETP's claims of breach of contract and unfair competition and against Enbridge based on ETP's claims of tortious interference with contractual relations.

ETP Revolving Credit Facility

On October 27, 2011, ETP amended and restated the its revolving credit facility (the “ETP Credit Facility”) to, among other things, (i) allow for borrowings of up to $2.5 billion; (ii) extend the maturity date from July 20, 2012 to October 27, 2016 (which may be extended by one year with lender approval); (iii) allow for an increase in the size of the credit facility to $3.75 billion (subject to obtaining lender commitments for the additional borrowing capacity); and (iv) to adjust the interest rates and commitment fees to current market terms. Following this amendment and based on ETP's current ratings, the interest margin for LIBOR rate loans is 1.50% and the commitment fee for unused borrowing capacity is 0.25%.

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.

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Consolidated Results



	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Revenues	$	2,097,866		$	1,587,807		$	510,059		$	6,061,892		$	4,822,316		$	1,239,576
Cost of products sold	1,353,037			995,105			357,932			3,818,615			3,060,423			758,192
Gross margin	744,829			592,702			152,127			2,243,277			1,761,893			481,384
Operating expenses	234,282			208,809			25,473			677,695			559,302			118,393
Depreciation and amortization	157,952			120,315			37,637			445,738			304,681			141,057
Selling, general and administrative	82,587			61,526			21,061			225,032			177,673			47,359
Operating income	270,008			202,052			67,956			894,812			720,237			174,575
Interest expense, net of interest capitalized	(193,772		)	(209,871		)	16,099			(543,218		)	(460,578		)	(82,640		)
Equity in earnings of affiliates	28,374			22,349			6,025			82,634			40,723			41,911
Losses on non-hedged interest rate derivatives	(68,497		)	(31,966		)	(36,531		)	(65,094		)	(68,858		)	3,764
Impairment of investments in affiliates	(5,355		)	—			(5,355		)	(5,355		)	(52,620		)	47,265
Other, net	33,231			14,379			18,852			21,081			10,819			10,262
Income tax expense	(3,290		)	(2,093		)	(1,197		)	(18,417		)	(11,357		)	(7,060		)
Income from discontinued operations	—			324			(324		)	—			410			(410		)
Net income (loss)	$	60,699		$	(4,826	)	$	65,525		$	366,443		$	178,776		$	187,667

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. The Parent Company's 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 September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Selling, general and administrative	$	(11,667	)	$	(2,920	)	$	(8,747	)	$	(25,546	)	$	(20,335	)	$	(5,211	)
Interest expense, net of interest capitalized	(40,819		)	(89,484		)	48,665			(122,345		)	(126,400		)	4,055
Equity in earnings of affiliates	102,565			102,388			177			369,833			324,128			45,705
Losses on non-hedged interest rate derivatives	—			(18,211		)	18,211			—			(53,388		)	53,388
Other, net	19,068			(6,736		)	25,804			2,256			(6,949		)	9,205

Selling, general and administrative. For the three and nine months ended September 30, 2011 compared to the same periods in the prior year, selling, general and administrative expense increased primarily due to an increase in acquisition-related costs associated with the SUG Merger.

Interest Expense. For the three and nine months ended September 30, 2011 compared to the same period in the prior year, interest expense decreased primarily due to the recognition of $66.4 million of realized losses on hedged interest rate swaps in September

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2010 in connection with the refinancing of indebtedness that would have come due in 2011 and 2012. These realized losses were offset by an increase in interest expense that primarily resulted from the Parent Company's issuance of $1.8 billion aggregate principal amount of 7.5% senior notes in September 2010.

In addition, interest expense for the periods presented reflected distributions on the ETE Preferred Units issued by ETE in connection with the acquisition of a controlling interest in Regency in May 2010. Distributions on ETE Preferred Units were $6 million and $18 million for the three and nine months ended September 30, 2011, respectively, compared to $6 million and $8.4 million for the three and nine months ended September 30, 2010, respectively.

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investments in ETP and Regency. The Parent Company recorded equity in earnings of ETP of $95.4 million and $99.8 million for the three months ended September 30, 2011 and 2010, respectively, and $355.1 million and $322.0 million for the nine months ended September 30, 2011 and 2010, respectively. An analysis of ETP’s operating results is included in “Segment Operating Results” below. The Parent Company recorded equity in earnings of Regency of $7.2 million and $2.5 million for the three months ended September 30, 2011 and 2010, respectively, and $14.7 million and $2.1 million for the nine months ended September 30, 2011 and 2010, respectively, which represented only the period subsequent to the Parent Company’s acquisition of a controlling interest in Regency on May 26, 2010.

Losses on Non-Hedged Interest Rate Derivatives. The Parent Company terminated its interest rate swaps that were not accounted for as hedges in September 2010 in connection with the issuance of $1.8 billion of senior notes. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings.

Other, net. Other expenses decreased between periods primarily due to non-cash charges recorded to decrease the carrying value of the ETE Preferred Units that were issued by the Parent Company in connection with the acquisition of a controlling interest in Regency in May 2010.

Segment Operating Results

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


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


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

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

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

Net income (loss) by segment is as follows:



	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Investment in ETP	$	76,050		$	107,387		$	(31,337	)	$	479,868		$	390,341		$	89,527
Investment in Regency	30,849			7,846			23,003			59,991			2,951			57,040
Corporate and Other	(36,915		)	(120,059		)	83,144			(155,743		)	(214,516		)	58,773
Adjustments and Eliminations	(9,285		)	—			(9,285		)	(17,673		)	—			(17,673		)
Net income (loss)	$	60,699		$	(4,826	)	$	65,525		$	366,443		$	178,776		$	187,667

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Investment in ETP



	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Revenues	$	1,715,316		$	1,290,644		$	424,672		$	5,030,988		$	4,430,331		$	600,657
Cost of products sold	1,075,526			777,411			298,115			3,078,611			2,773,133			305,478
Gross margin	639,790			513,233			126,557			1,952,377			1,657,198			295,179
Operating expenses	196,737			174,740			21,997			574,528			515,021			59,507
Depreciation and amortization	112,942			85,612			27,330			313,878			252,765			61,113
Selling, general and administrative	57,768			44,734			13,034			158,074			137,743			20,331
Operating income	272,343			208,147			64,196			905,897			751,669			154,228
Interest expense, net of interest capitalized	(124,000		)	(101,241		)	(22,759		)	(347,706		)	(309,217		)	(38,489		)
Equity in earnings of affiliates	6,713			595			6,118			13,386			10,848			2,538
Losses on non-hedged interest rate derivatives	(68,595		)	(11,963		)	(56,632		)	(64,705		)	(11,963		)	(52,742		)
Impairment of investments in affiliates	(5,355		)	—			(5,355		)	(5,355		)	(52,620		)	47,265
Other, net	(1,017		)	13,842			(14,859		)	(1,230		)	14,110			(15,340		)
Income tax expense	(4,039		)	(1,993		)	(2,046		)	(20,419		)	(12,486		)	(7,933		)
Net income	$	76,050		$	107,387		$	(31,337	)	$	479,868		$	390,341		$	89,527

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

•

Revenues generated by ETP’s interstate transportation systems increased $45.4 million and $117 million, respectively, for the three and nine months ended September 30, 2011 compared to the prior period primarily as a result of the Tiger pipeline being placed into service in December 2010 with an additional expansion placed in service on August 1, 2011. Increased revenue from the Tiger pipeline was partially offset by decreased revenue from the Transwestern pipeline.


•	Gross margin from ETP’s midstream business increased by $31.4 million and $69.2 million for the three and nine months ended September 30, 2011, respectively. These increases were driven by higher volumes primarily from recent acquisitions and growth project as well as the impacts of favorable NGL prices.


•	Gross margin from ETP’s NGL transportation and services business was $65.4 million and $111.8 million for the three and nine months ended September 30, 2011, respectively, which represented 100% of the results from Lone Star since it was acquired in May 2011. Accordingly, no comparative amounts were reflected in ETP’s results prior to May 2, 2011.

Operating Expenses. For the three and nine months ended September 30, 2011 compared to the same period in the prior year, ETP’s operating expenses increased primarily due to operating expenses from ETP’s Tiger pipeline and operating expenses of $16.6 million and $23.1 million, respectively, from Lone Star, which was acquired on May 2, 2011.

Depreciation and Amortization. ETP’s depreciation and amortization expense increased primarily due to incremental depreciation associated with ETP’s Tiger pipeline and the continued expansion of ETP’s Louisiana and South Texas midstream assets. In addition, the three and nine months ended September 30, 2011 reflected $12.9 million and $20 million, respectively, of depreciation recorded by Lone Star since the LDH Acquisition on May 2, 2011.

Selling, General and Administrative. For the three and nine months ended September 30, 2011, ETP’s selling, general and administrative expenses increased primarily due to increased allocated and employee-related costs related to the Tiger Pipeline and increased selling, general and administrative costs related to Lone Star.

Interest Expense. Interest expense increased for the three and nine months ended September 30, 2011 compared to the same periods last year principally due to ETP's issuance of $1.5 billion of senior notes in May 2011, the proceeds from which were used to repay borrowings under the ETP Credit Facility, to fund growth projects and for general partnership purposes. Interest expense was presented net of capitalized interest and allowance for debt funds used during construction, which totaled $4.3 million and $7.1 million for the three months ended September 30, 2011 and 2010, respectively, and $9.5 million and $11 million for the nine months ended September 30, 2011 and 2010, respectively.

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Equity in Earnings of Affiliates. ETP's equity in earnings of affiliates for the three and nine months ended September 30, 2011 primarily reflected equity in earnings related to Fayetteville Express Pipeline LLC (“FEP”). Equity in earnings of affiliates for the nine months ended September 30, 2010 were primarily related to Midcontinent Express Pipeline LLC (“MEP”), for which substantially all of ETP's interest was transferred on May 26, 2010 to Regency.

Losses on Non-Hedged Interest Rate Derivatives. Losses on non-hedged interest rate derivatives for the three and nine months ended September 30, 2011 reflected settlements and unrealized gains and losses on ETP's interest rate swaps. As of September 30, 2011, ETP had a total notional amount of $1.65 billion of interest rate swaps outstanding compared to $400 million as of September 30, 2010. The $1.65 billion of swaps included $1.15 billion of forward-starting floating-to-fixed swaps used to hedge interest rates associated with anticipated note issuances and $500 million of fixed-to-floating swaps used to swap a portion of its fixed rate debt to floating. During the three months ended September 30, 2011, forward rates decreased significantly due to the global economic uncertainty which resulted in unrealized non-cash losses on ETP's forward-starting floating-to-fixed swaps.

Impairment of Investments in Affiliates. For the three and nine months ended September 30, 2011, ETP's results reflected a non-cash charge to write off all of its investment in a joint venture for which projects are no longer being pursued. In conjunction with the transfer of ETP's interest in MEP on May 26, 2010, ETP recorded a non-cash charge of approximately $52.6 million during the nine months ended September 30, 2010 to reduce the carrying value of its interest to MEP's estimated fair value.

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

Investment in Regency



	Three Months Ended September 30,									Nine Months Ended September 30,
	2011			2010			Change			2011			2010			Change
Revenues	$	390,267		$	296,888		$	93,379		$	1,064,017		$	393,868		$	670,149
Cost of products sold	279,526			213,032			66,494			755,262			283,206			472,056
Gross margin	110,741			83,856			26,885			308,755			110,662			198,093
Operating expenses	37,950			34,306			3,644			105,506			44,708			60,798
Depreciation and amortization	41,956			32,205			9,751			122,695			42,750			79,945
Selling, general and administrative	17,350			18,072			(722		)	54,010			25,176			28,834
(Gains) losses on disposal of assets	(131		)	200			(331		)	50			210			(160		)
Operating income (loss)	13,616			(927		)	14,543			26,494			(2,182		)	28,676
Interest expense, net of interest capitalized	(28,852		)	(20,379		)	(8,473		)	(73,548		)	(28,460		)	(45,088		)
Equity in earnings of affiliates	30,946			21,754			9,192			86,921			29,875			57,046
Other, net	15,050			7,524			7,526			20,105			4,003			16,102
Income tax benefit (expense)	89			(450		)	539			19			(695		)	714
Income from discontinued operations	—			324			(324		)	—			410			(410		)
Net income	$	30,849		$	7,846		$	23,003		$	59,991		$	2,951		$	57,040

ETE obtained control of Regency on May 26, 2010. Changes between the nine-month periods were primarily due to the consolidation of Regency beginning May 26, 2010 and also were impacted by changes during the three-month periods, as discussed below.

Gross Margin. For the three months ended September 30, 2011 compared to the three months ended September 30, 2010, Regency's gross margin increased primarily due to additional gathering and processing margins resulting from higher volumes in the Eagle Ford Shale and west Texas.

Operating Expenses. For the three months ended September 30, 2011 compared to the three months ended September 30, 2010, Regency's operating expenses increased primarily due to higher short-term incentives accruals and an increase in pipeline maintenance expenses.

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Depreciation and Amortization. For the three months ended September 30, 2011 compared to the three months ended September 30, 2010, Regency's depreciation and amortization expense increased primarily due to the completion of various growth projects since September 2010 as well as Regency's acquisition of its contract treating business in September 2010.

Interest Expense. For the three months ended September 30, 2011 compared to the three months ended September 30, 2010, Regency's interest expense increased primarily due to interest associated with $500 million of senior notes issued by Regency in May 2011.

Equity in Earnings of Affiliates. For the three months ended September 30, 2011 compared to the three months ended September 30, 2010, Regency's equity in earnings of affiliates increased primarily due to Regency's acquisition of its 30% interest in Lone Star in May 2011.

Other, net. For the three months ended September 30, 2011 compared to the three months ended September 30, 2010, Regency's other, net increased primarily due to non-cash mark-to-market adjustments on the embedded derivatives related to Regency's Series A Preferred Units, which were reflected as preferred units of subsidiary on ETE's consolidated balance sheet.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The principal sources of the Parent Company’s cash flow are its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The amount of cash that ETP and Regency distribute to their partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP and Regency. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

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

ETE intends to finance a portion of the cash component of the SUG Merger consideration with debt financing. In connection with entering into the merger agreement, ETE has entered into a senior bridge term loan credit agreement (the "Bridge Loan Agreement") with the Bridge Lenders, pursuant to which, subject to the conditions set forth therein, the Bridge Lenders have agreed to provide a 364-day Bridge Term Loan Facility in an aggregate principal amount of $3.7 billion. ETE's ability to borrow under the Bridge Loan Agreement is subject to the satisfaction of certain conditions precedent, including the delivery of certain documents requested by the administrative agent (such as financial statements, favorable opinions of counsel and customary corporate authorization documents) and the payment of relevant fees and expenses. ETE may use the proceeds of the loans under the Bridge Loan Agreement to finance the SUG Merger, to repay its remaining indebtedness under Parent Company Credit Agreement (to the extent repaid on the date of initial borrowing under the Bridge Loan Agreement) and to pay transaction costs related to the consummation of the SUG Merger and the Bridge Loan Agreement.

The maturity date of a portion of the Bridge Loan Agreement may be extended, at ETE's option, from 364 days to 15 months, subject to certain conditions, including payment by ETE of certain applicable fees to the Bridge Lenders. During the period from the closing date until the 60^th day thereafter, any amounts borrowed under the Bridge Loan Agreement will bear interest at either (a) the Alternate Base Rate (as defined in the Bridge Loan Agreement) plus 3.00% or (b) the adjusted LIBOR rate for a one or two month interest period beginning on such day plus 4.00%, in either case with the adjusted LIBOR rate being subject to a minimum floor of 1.0% per annum. During the period from and after the 61^st day following the closing date until the loans are paid in full, any amounts borrowed under the Bridge Loan Agreement will bear interest at a rate that corresponds to the rating maintained by Standard & Poor's and Moody's for senior, unsecured, non-credit enhanced, long-term debt of ETE, which rate may range from 10.5% to 13.0%, plus the lesser of (a) 1.0% and (b) a number of basis points based on changes in the Double-B Sector

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of the Credit Suisse High Yield Index.

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

ETP

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

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


•	growth capital expenditures for its midstream and intrastate transportation and storage operations, primarily for construction of new pipelines and compression, for which ETP expects to spend between $200 million and $250 million for the remainder of 2011 and between $600 million and $750 million for 2012;


•	growth capital expenditures for its interstate transportation operations, excluding capital contributions to its joint ventures as discussed below, for the construction of new pipelines for which ETP expects to spend between $5 million and $10 million for the remainder of 2011;


•	growth capital expenditures for ETP’s NGL transportation and services operations of between $250 million and $300 million for the remainder of 2011 and between $700 million and $750 million for 2012;


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

•

maintenance capital expenditures of between $40 million and $50 million for the remainder of 2011, which include (i) capital expenditures for its intrastate operations for pipeline integrity and for connecting additional wells to its intrastate natural gas systems in order to maintain or increase throughput on existing assets; (ii) capital expenditures for its interstate operations, primarily for pipeline integrity; and (iii) capital expenditures related to NGL transportation and services, which includes amounts ETP expects to be funded by Regency related to its 30% interest in Lone Star; and (iv) capital expenditures for its propane operations to extend the useful lives of its existing propane assets in order to sustain its operations, including vehicle replacements on its propane vehicle fleet. ETP also expects to spend between $120 million and $130 million in maintenance capital expenditures for 2012.

As discussed in Note 3 to our consolidated financial statements, ETP entered into the Amended Citrus Merger Agreement on July 19, 2011. ETP expects to fund substantially all of the cash portion of the purchase price initially through the issuance of debt and borrowings from the ETP Credit Facility. ETP also intends to issue sufficient additional equity to maintain its investment grade credit rating and to use the proceeds from such equity issuances to repay other indebtedness and fund capital expenditures. In addition, ETP may enter into other acquisitions, including the potential acquisition of new pipeline systems.

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

ETP raised $695.5 million in proceeds, net of commissions, from its common unit offering in April 2011 and $7.6 million in net proceeds from the issuance of 175,863 ETP Common Units in connection with its distribution reinvestment plan (“DRIP”). In addition, ETP raised $96.3 million in net proceeds during the nine months ended September 30, 2011 under ETP’s equity distribution program, as described in Note 11 to our consolidated financial statements. As of September 30, 2011, in addition to $136.2 million of cash on hand, ETP had available capacity under the ETP Credit Facility of $1.4 billion. Based on current estimates, ETP expects to utilize capacity under the ETP Credit Facility, along with cash from its operations, to fund its announced growth capital expenditures and working capital needs through the end of 2011; however, ETP may issue debt or equity securities prior to that time as it deems prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.

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Regency

Regency expects its sources of liquidity to include:


•	cash generated from operations;


•	borrowings under its revolving credit facility (the “Regency Credit Facility”);


•	distributions received from unconsolidated affiliates;


•	debt offerings; and


•	issuance of additional partnership units.

As of September 30, 2011, in addition to approximately $5.2 million of cash on hand, Regency had available capacity under the Regency Credit Facility of approximately $435 million. Regency raised $231.9 million in proceeds, net of commissions, from its common unit offering in October 2011.

Regency expects its growth capital expenditures to be approximately $373 million in 2011, which includes $200 million for its gathering and processing operations, mostly in South Texas, $95 million for its contract compression operations, $65 million for its joint ventures, $9 million for its contract treating operations, and $4 million for its corporate and other operations. In addition, Regency expects its maintenance capital expenditures to be $17 million in 2011.

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

In 2012, Regency expects to invest between $630 million and $680 million in growth capital expenditures, of which $290 million is expected to be invested in organic growth projects in its gathering and processing operations, including a portion for its south Texas gathering system expansion, between $250 million and $300 million is expected to be invested in its portion of growth capital expenditures for Lone Star, $70 million is expected to be invested in the fabrication of new compressor packages for its contract compression operations, $15 million is expected to be invested in the fabrication of new treating plants for its contract treating operations and $5 million is expected to be invested in its corporate and other operations.

For the nine months ended September 30, 2011, Regency incurred $258 million of growth capital expenditures, which primarily related to $172 million for organic growth projects for its gathering and processing operations, $68 million for the fabrication of new compressor packages for its contract compression operations, $10 million for growth projects for its joint ventures, $5 million for the fabrication of new treating plants for its contract treating operations and $3 million for vehicle purchases in its corporate and others operations. For the nine months ended September 30, 2011, Regency incurred $14 million of maintenance capital expenditures.

Regency may revise the timing of these expenditures as necessary to adapt to economic conditions. Regency expects to fund its growth capital expenditures with borrowings under its revolving credit facility and a combination of debt and equity issuances.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price for 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.

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Nine Months Ended September 30, 2011 compared to nine months ended September 30, 2010. Cash provided by operating activities during 2011 was $1.1 billion as compared to $927.7 million for 2010. Net income was $366.4 million and $178.8 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 $496.9 million and $388.7 million and changes in operating assets and liabilities of $234.2 million and $430.8 million for 2011 and 2010, respectively.

The non-cash activity in 2011 and 2010 consisted primarily of depreciation and amortization of $445.7 million and $304.7 million, respectively. In addition, non-cash compensation expense was $34.4 million and $23.5 million for 2011 and 2010, respectively.

Cash paid for interest, net of interest capitalized, was $489.6 million and $429.7 million for the nine months ended September 30, 2011 and 2010, respectively.

Investing Activities

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

Nine Months Ended September 30, 2011 compared to nine months ended September 30, 2010. Cash used in investing activities during 2011 was $3.34 billion as compared to $1.4 billion for 2010. In 2011, our subsidiaries paid cash for acquisitions of $1.97 billion, which primarily consisted of the acquisition of Lone Star and made net advances to joint ventures of $166.5 million. In 2010, Regency paid cash for acquisitions of $191.3 million, ETP paid cash for acquisitions of $156.4 million, we received $24 million in cash in the acquisition of Regency, and Regency received $70.2 million in cash for the sale of its East Texas assets. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2011 were $1.23 billion, including changes in accruals of $28.5 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2010 of $1.13 billion, including changes in accruals of $21.2 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.

Nine Months Ended September 30, 2011 compared to nine months ended September 30, 2010. Cash provided by financing activities during 2011 was $2.31 billion as compared to $489.8 million for 2010. In 2011, ETP received $799.3 million in net proceeds from offerings of ETP Common Units, including $96.3 million under ETP’s equity distribution program (see Note 11 to our consolidated financial statements), as compared to $1.09 billion in 2010, which included $174.1 million under ETP’s equity distribution program. During 2011, we had a consolidated net increase in our debt level of $2.3 billion as compared to a net decrease of $206.6 million for 2010, primarily due to ETP’s issuance of $1.5 billion of principal amount of senior notes in May 2011 and Regency’s issuance of $500 million of principal amount senior notes in May 2011. We paid distributions of $385.8 million and $362.3 million to our partners in 2011 and in 2010. In addition, during 2011 and 2010, ETP paid distributions of $417.2 million and $348.3 million, respectively, on limited partner interests other than those held by the Parent Company. During 2011 and 2010, Regency paid distributions of $157.1 million and $42.5 million, respectively, on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interest on our consolidated statements of cash flows.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	September 30, 2011			December 31, 2010
Parent Company Indebtedness:
ETE Senior Notes	$	1,800,000		$	1,800,000
Subsidiary Indebtedness:
ETP Senior Notes	6,550,000			5,050,000
Regency Senior Notes	1,350,000			850,000
Transwestern Senior Unsecured Notes	870,000			870,000
HOLP Senior Secured Notes	73,314			103,127
ETP Revolving Credit Facility	574,607			402,327
Regency Revolving Credit Facility	445,000			285,000
Other long-term debt	11,235			9,671
Unamortized discounts, net	(10,343		)	(6,013		)
Fair value adjustments related to interest rate swaps	13,051			17,260
Total debt	11,676,864			9,381,372
Less: current maturities	424,119			35,305
Long-term debt, less current maturities	$	11,252,745		$	9,346,067

The terms of our consolidated indebtedness are described in more detail in our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on February 28, 2011 and in Note 9 to our consolidated financial statements.

Revolving Credit Facilities

ETP Credit Facility. The 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 September 30, 2011, ETP had a balance of $574.6 million outstanding under the ETP Credit Facility, and the amount available under the ETP Credit Facility was $1.4 billion, taking into account letters of credit of $24.3 million. The weighted average interest rate on the total amount outstanding at September 30, 2011 was 0.80%.

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

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

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As of September 30, 2011, there was a balance outstanding under the Regency Credit Facility of $445 million in revolving credit loans and approximately $20 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2011, which is reduced by any letters of credit, was approximately $435 million. The weighted average interest rate on the total amount outstanding as of September 30, 2011 was 3.03%.

Senior Notes

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

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

Regency. In May 2011, Regency issued $500 million in senior notes that mature on July 15, 2021. The senior notes bear interest at 6.50% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. Regency used the proceeds, net of commissions, of approximately $491.3 million to repay borrowings outstanding under the Regency Credit Facility. Regency capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the notes. Interest will be paid semi-annually and mature on July 15, 2021.

Covenants Related to Our Credit Agreements

CASH DISTRIBUTIONS

Cash Distributions Paid by the Parent Company

Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements.

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



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2010	February 7, 2011	February 18, 2011	$	0.540
March 31, 2011	May 6, 2011	May 19, 2011	0.560
June 30, 2011	August 5, 2011	August 19, 2011	0.625
September 30, 2011	November 4, 2011	November 18, 2011	0.625

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



	Nine Months Ended September 30,
	2011		2010
Limited Partners	$	403,564	$	361,164
General Partner interest	1,254		1,122
Total ETE distributions	$	404,818	$	362,286

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Cash Distributions Received from Subsidiaries

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



	Nine Months Ended September 30,
	2011		2010
Distributions from ETP:
Limited Partners	$	134,670	$	145,640
General Partner interest	14,690		14,634
Incentive Distribution Rights	310,254		279,823
Total distributions from ETP	459,614		440,097
Distributions from Regency:
Limited Partners	35,460		23,378
General Partner interest	3,861		2,372
Incentive Distribution Rights	4,133		1,965
Total distributions from Regency	43,454		27,715
Total distributions received from subsidiaries	$	503,068	$	467,812

Cash Distributions Paid by Subsidiaries

ETP and Regency are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

Cash Distributions Paid by ETP

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



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2010	February 7, 2011	February 14, 2011	$	0.89375
March 31, 2011	May 6, 2011	May 16, 2011	0.89375
June 30, 2011	August 5, 2011	August 15, 2011	0.89375
September 30, 2011	November 4, 2011	November 14, 2011	0.89375

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



	Nine Months Ended September 30,
	2011		2010
Limited Partners:
Common Units	$	560,281	$	503,582
Class E Units	9,363		9,363
General Partner interest	14,690		14,634
Incentive Distribution Rights	310,254		279,823
Total ETP distributions	$	894,588	$	807,402

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Cash Distributions Paid by Regency

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



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	0.445
June 30, 2011	August 5, 2011	August 12, 2011	0.450
September 30, 2011	November 7, 2011	November 14, 2011	0.455

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



	Nine Months Ended September 30,
	2011		2010
Limited Partners	$	203,114	$	114,270
General Partner interest	3,861		2,372
Incentive Distribution Rights	4,133		1,965
Total Regency distributions	$	211,108	$	118,607

NEW ACCOUNTING STANDARDS

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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2010, in addition to the interim unaudited consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2010. Since December 31, 2010, there have been no material changes to our primary market risk exposures or how those exposures are managed.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Commodity Price Risk

The tables below summarize by segment commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of September 30, 2011 and December 31, 2010.

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in our consolidated results of operations or other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of ETP’s and Regency’s total derivative portfolios may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

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

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Investment in ETP

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



	September 30, 2011							December 31, 2010
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX	(39,952,500	)	$	6,225		$	906	(38,897,500	)	$	(2,334	)	$	304
Swing Swaps IFERC	30,517,500		(889		)	2,323		(19,720,000	)	(2,086		)	2,228
Fixed Swaps/Futures	(15,517,500	)	(9,730		)	6,073		(2,570,000	)	(11,488		)	1,176
Forward Physical Contracts (MMbtu)	12,324,054		255			1,210		—		—			—
Options — Calls	—		—			—		(3,000,000	)	62			7
Propane:
Forwards/Swaps	52,668,000		(2,008		)	7,685		1,974,000		275			258
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX	(19,685,000	)	(251		)	167		(28,050,000	)	722			322
Fixed Swaps/Futures	(29,837,500	)	30,695			12,267		(39,105,000	)	8,599			16,837
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures	460,000		4			204		(210,000	)	232			93
Options — Puts	9,390,000		8,955			3,220		26,760,000		10,545			7,125
Options — Calls	(9,390,000	)	2,587			67		(26,760,000	)	4,812			1,565
Propane:
Forwards/Swaps	—		—			—		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.



	September 30, 2011						December 31, 2010
	Notional Volume	Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume	Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Cash Flow Hedging Derivatives
Natural Gas:
Fixed Swaps/Futures	2,934,000	$	2,806		$	1,216	3,830,000	$	2,053		$	1,684
Propane:
Forwards/Swaps	15,204,000	(4,029		)	2,078		18,648,000	(4,203		)	2,277
NGLs:
Forwards/Swaps	771,000	(7,116		)	3,876		1,212,110	(6,288		)	4,910
WTI Crude:
Forwards/Swaps	417,000	4,817			3,387		373,655	(3,581		)	3,501

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Interest Rate Risk

As of September 30, 2011, ETP had $574.6 million of floating rate debt outstanding under its revolving credit facility and Regency had $445 million of variable rate debt outstanding under its revolving credit facility. ETE had no variable rate debt outstanding as of September 30, 2011. A hypothetical change of 100 basis points would result in a change to interest expense of $10.2 million annually. We manage a portion of our interest rate exposure by utilizing interest rate swaps and similar arrangements. To the extent that we have debt with floating interest rates that are not hedged, our results of operations, cash flows and financial condition could be adversely affected by increases in interest rates. The following interest rate swaps were outstanding as of September 30, 2011 and December 31, 2010 (dollars in thousands), none of which are designated as hedges for accounting purposes:

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

September 30, 2011

December 31, 2010

ETP

May 2012 ⁽²⁾

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

350,000

—

ETP

August 2012⁽²⁾

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

500,000

400,000

ETP

July 2013 ⁽²⁾

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

300,000

—

ETP

July 2018

Pay a floating rate plus a spread of 4.01% 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⁾	As of September 30, 2011. Floating rates are based on 3-month LIBOR.


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

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in losses on non-hedged interest rate derivatives) of approximately $81.5 million as of September 30, 2011 and $1.3 million as of December 31, 2010. For ETP’s $500 million of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow (swap settlements) of $5 million annually. For ETP’s forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

Credit Risk

ETP’s counterparties consist primarily of petrochemical companies and other industrial, mid-size to major oil and gas companies and power companies. This concentration of counterparties may impact its overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.

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

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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 September 30, 2011 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

Effective January 1, 2011, we began to integrate certain of Regency’s business functions under a shared services agreement with ETE Services Company, LLC. In connection with this integration, certain of Regency’s controls and procedures have been changed to conform to the existing controls of our other subsidiaries.

The acquisition of LDH (the “LDH Acquisition”) was closed on May 2, 2011 and we are currently evaluating the internal control structure of LDH. In recording the LDH Acquisition, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of Lone Star that were included in our earnings for the three months ended September 30, 2011.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2010 and Note 14 — Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2011.

ITEM 1A. RISK FACTORS

For information regarding risks, uncertainties and assumptions, see “Part I — Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2010 and “Part II — Other Information – Item 1A. Risk Factors” of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011. There are no material changes from risk factors previously disclosed on Form 10-K for the year ended December 31, 2010 and on Form 10-Q for the quarters ended March, 31, 2011 and June 30, 2011.

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.

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ITEM 6. EXHIBITS

(a) Exhibits

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



	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
2.1	1-32740 (8-K) (6/20/11)	2.1	Agreement and Plan of Merger, by and among, Energy Transfer Equity, L.P., Sigma Acquisition Corporation, and Southern Union Company, dated as of June 15, 2011.
2.2	1-32740 (8-K)(7/5/11)	2.1	Agreement and Plan of Merger, by and among, Energy Transfer Equity, L.P., Sigma Acquisition Corporation, and Southern Union Company, dated as of June 15, 2011, as Amended and Restated as of July 4, 2011.
2.2.1	1-32740 (8-K)(7/5/11)	10.1	Support Agreement dated June 15, 2011 by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation, and certain stockholders of Southern Union Company.
2.2.2	1-32740 (8-K)(7/5/11)	10.3	Consulting Agreement dated June 15, 2011, by and among, Southern Union Company, Energy Transfer Equity, L.P. and George L. Lindemann.
2.2.3	1-32740 (8-K)(7/5/11)	10.2	Consulting Agreement dated June 15, 2011, by and among, Southern Union Company, Energy Transfer Equity, L.P. and Eric D. Herschmann.
2.4	1-32740 (8-K)(7/20/11)	2.2	Amended and Restated Agreement and Plan of Merger, by and among, Energy Transfer Partners, L.P., Citrus ETP Acquisition L.L.C., Energy Transfer Equity, L.P., Southern Union Company, and CrossCountry Energy, LLC, dated as of July 19, 2011.
2.5	1-32740 (8-K)(9/15/11)	2.1	Amendment No. 1, dated as of September 14, 2011, to Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation and Southern Union Company.
2.6	1-32740 (8-K)(9/15/11)	2.2	Amendment No. 1, dated as of September 14, 2011, to Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P.
10.1	1-32740 (8-K)(7/5/11)	10.5	Amended and Restated Support Agreement dated July 4, 2011 by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation and certain stockholders of Southern Union Company
10.2	1-32740 (8-K)(7/20/11)	10.1	Second Amended and Restated Support Agreement, dated as of July 19, 2011, by and among, Energy Transfer Equity, L.P., Sigma Acquisition Corporation and certain stockholders of Southern Union Company.
31.1			Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			Certification of President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101			Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010; (ii) our Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010; (iii) our Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2011 and 2010; (iv) our Consolidated Statement of Equity for the nine months ended September 30, 2011; (v) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010; and (vi) the notes to our Consolidated Financial Statements.

_________________

* Incorporated herein by reference.

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SIGNATURE

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



		ENERGY TRANSFER EQUITY, L.P.

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

Date:	November 7, 2011	By:	/s/ John W. McReynolds
			John W. McReynolds
			President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)