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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

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

For the quarterly period ended September 30, 2010

or

 

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

Commission file number 1-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)

 

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

3738 Oak Lawn Avenue, Dallas, Texas 75219

(Address of principal executive offices and zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

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

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

 

Large accelerated filer		x		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  x

At November 3, 2010, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P. 222,941,172 Common Units

 

 

 

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FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries

 

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Condensed Consolidated Balance Sheets – September 30, 2010 and December 31, 2009			1
Condensed Consolidated Statements of Operations – Three and Nine Months Ended September  30, 2010 and 2009			3
Condensed Consolidated Statements of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2010 and 2009			4
Condensed Consolidated Statement of Equity – Nine Months Ended September 30, 2010			5
Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010 and 2009			6
Notes to Condensed Consolidated Financial Statements			7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			47
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			64
ITEM 4. CONTROLS AND PROCEDURES			66
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			68
ITEM 1A. RISK FACTORS			68
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			68
ITEM 3. DEFAULTS UPON SENIOR SECURITIES			68
ITEM 4. [RESERVED]
ITEM 5. OTHER INFORMATION			68
ITEM 6. EXHIBITS			69
SIGNATURE			71

 

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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” or “the Partnership”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include certain “forward-looking” statements. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect” “continue,” “estimate,” “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.

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part II Other Information – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010, as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (“SEC”) on February 24, 2010.

Definitions

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

 

 

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

		September 30, 2010				December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	88,113			$	68,315
Marketable securities			2,270				6,055
Accounts receivable, net of allowance for doubtful accounts of $6,957 and $6,338 as of September 30, 2010 and December 31, 2009, respectively			503,743				566,522
Accounts receivable from related companies			62,065				51,894
Inventories			281,509				389,954
Exchanges receivable			18,919				23,136
Price risk management assets			16,268				12,371
Other current assets			128,343				149,712
Total current assets			1,101,230				1,267,959
PROPERTY, PLANT AND EQUIPMENT			12,863,914				10,117,041
ACCUMULATED DEPRECIATION			(1,286,200	)			(1,052,566	)
			11,577,714				9,064,475
ADVANCES TO AND INVESTMENTS IN AFFILIATES			1,324,428				663,298
LONG-TERM PRICE RISK MANAGEMENT ASSETS			644				—
GOODWILL			1,592,203				775,094
INTANGIBLES AND OTHER ASSETS, net			1,255,128				389,683
Total assets		$	16,851,347			$	12,160,509

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

		September 30, 2010				December 31, 2009
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	411,935			$	359,176
Accounts payable to related companies			13,392				38,515
Exchanges payable			11,504				19,203
Price risk management liabilities			5,865				65,146
Accrued and other current liabilities			550,102				366,781
Current maturities of long-term debt			35,221				40,924
Total current liabilities			1,028,019				889,745
LONG-TERM DEBT, less current maturities			8,800,057				7,750,998
SERIES A CONVERTIBLE PREFERRED UNITS (Note 11)			304,950				—
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES			60,470				73,332
OTHER NON-CURRENT LIABILITIES			236,544				226,183
COMMITMENTS AND CONTINGENCIES (Note 15)
PREFERRED UNITS OF SUBSIDIARY (Note 11)			70,896				—
EQUITY:
PARTNERS’ CAPITAL:
General Partner			633				368
Limited Partners:
Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at September 30, 2010 and December 31, 2009, respectively)			151,535				53,412
Accumulated other comprehensive income (loss)			12,231				(53,628	)
Total partners’ capital			164,399				152
Noncontrolling interest			6,186,012				3,220,099
Total equity			6,350,411				3,220,251
Total liabilities and equity		$	16,851,347			$	12,160,509

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
REVENUES:
Natural gas operations		$	1,380,029			$	943,975			$	3,827,506			$	3,004,163
Retail propane			183,786				162,224				914,372				829,901
Other			23,992				23,650				80,438				77,449
Total revenues			1,587,807				1,129,849				4,822,316				3,911,513
COSTS AND EXPENSES:
Cost of products sold — natural gas operations			883,716				591,797				2,520,157				1,865,914
Cost of products sold — retail propane			104,533				80,232				519,796				378,524
Cost of products sold — other			6,856				6,119				20,470				18,842
Operating expenses			208,809				158,883				559,302				517,337
Depreciation and amortization			120,315				84,738				304,681				239,626
Selling, general and administrative			61,526				34,579				177,673				146,640
Total costs and expenses			1,385,755				956,348				4,102,079				3,166,883
OPERATING INCOME			202,052				173,501				720,237				744,630
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized			(209,871	)			(120,100	)			(460,578	)			(341,050	)
Equity in earnings of affiliates			22,349				9,581				40,723				11,751
Gains (losses) on disposal of assets			81				(1,088	)			(408	)			(1,333	)
Gains (losses) on non-hedged interest rate derivatives			(31,966	)			(35,589	)			(68,858	)			24,373
Allowance for equity funds used during construction			12,432				30				18,039				18,618
Impairment of investment in affiliate			—				—				(52,620	)			—
Other, net			1,866				4,235				(6,812	)			4,559
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)			(3,057	)			30,570				189,723				461,548
Income tax expense (benefit)			2,093				(3,697	)			11,357				5,773
INCOME (LOSS) FROM CONTINUING OPERATIONS			(5,150	)			34,267				178,366				455,775
Income from discontinued operations			324				—				410				—
NET INCOME (LOSS)			(4,826	)			34,267				178,776				455,775
Less: Net income (loss) attributable to noncontrolling interest			10,511				(12,704	)			62,069				152,893
NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS			(15,337	)			46,971				116,707				302,882
GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)			(48	)			147				361				938
LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)		$	(15,289	)		$	46,824			$	116,346			$	301,944
BASIC NET INCOME (LOSS) PER LIMITED PARTNER UNIT		$	(0.07	)		$	0.21			$	0.52			$	1.35
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING			222,941,172				222,898,248				222,941,151				222,898,188
DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT		$	(0.07	)		$	0.21			$	0.52			$	1.35
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING			222,941,172				222,898,248				222,941,151				222,898,188

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
Net income (loss)		$	(4,826	)		$	34,267			$	178,776			$	455,775
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges			64,644				8,162				67,199				10,320
Change in value of derivative instruments accounted for as cash flow hedges			25,791				(27,663	)			30,291				(27,049	)
Change in value of available-for-sale securities			(732	)			3,049				(3,785	)			6,757
			89,703				(16,452	)			93,705				(9,972	)
Comprehensive income			84,877				17,815				272,481				445,803
Less: Comprehensive income (loss) attributable to noncontrolling interest			32,197				(19,635	)			89,915				142,353
Comprehensive income attributable to partners		$	52,680			$	37,450			$	182,566			$	303,450

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010

(Dollars in thousands)

(unaudited)

 

		General         Partner				Common     Unitholders				Accumulated Other Comprehensive Income (Loss)				Noncontrolling Interest				Total
Balance, December 31, 2009		$	368			$	53,412			$	(53,628	)		$	3,220,099			$	3,220,251
Regency Transactions (See Notes 1 and 3)			648				209,065				—				1,895,268				2,104,981
Distributions to ETE partners			(1,121	)			(361,165	)			—				—				(362,286	)
Subsidiary distributions			—				—				—				(390,805	)			(390,805	)
Subsidiary units issued for cash			415				133,587				—				1,352,861				1,486,863
Tax effect of remedial income allocation from tax amortization of goodwill			—				—				—				(2,552	)			(2,552	)
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings			—				685				—				21,750				22,435
Non-cash executive compensation			—				19				—				919				938
Other comprehensive income, net of tax			—				—				65,859				27,846				93,705
Other			(38	)			(414	)			—				(1,443	)			(1,895	)
Net income			361				116,346				—				62,069				178,776
Balance, September 30, 2010		$	633			$	151,535			$	12,231			$	6,186,012			$	6,350,411

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

 

		Nine Months Ended September 30,
		2010				2009
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	927,683			$	721,421
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired			(323,705	)			(6,244	)
Capital expenditures (excluding allowance for equity funds used during construction)			(1,125,104	)			(703,461	)
Contributions in aid of construction costs			12,048				5,251
Advances to affiliates, net of repayments			(44,968	)			(534,500	)
Proceeds from the sale of assets			84,044				13,235
Net cash used in investing activities			(1,397,685	)			(1,225,719	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			2,927,042				2,337,441
Principal payments on debt			(3,133,678	)			(1,816,884	)
Subsidiary equity offering, net of issue costs			1,486,863				578,924
Distributions to partners			(362,286	)			(351,037	)
Debt issuance costs			(35,612	)			(7,639	)
Distributions to noncontrolling interests			(390,805	)			(278,338	)
Other			(1,724	)			—
Net cash provided by financing activities			489,800				462,467
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			19,798				(41,831	)
CASH AND CASH EQUIVALENTS, beginning of period			68,315				92,023
CASH AND CASH EQUIVALENTS, end of period		$	88,113			$	50,192

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)

 

1.	OPERATIONS AND ORGANIZATION:

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

At September 30, 2010, our equity interests consisted of:

 

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

We acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions, that were completed on May 26, 2010. In the Regency Transactions, we:

 

•

acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Series A Convertible Preferred Units (the “Preferred Units”) having an aggregate liquidation preference of $300.0 million,

 

•

acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”) (see Note 8), and an option to acquire an additional 0.1% interest in MEP, in exchange for the redemption by ETP of approximately 12.3 million ETP Common Units we previously owned, and

 

•

acquired 26.3 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.

For additional information regarding the Regency Transactions, see Note 3.

The unaudited condensed consolidated financial statements of ETE presented herein for the three and nine month periods ended September 30, 2010 and 2009 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 interest in ETP and Regency.

The unaudited condensed consolidated financial statements include the results of Regency from May 26, 2010, the date ETE obtained control of Regency, through September 30, 2010.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include 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

 

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general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to fully understand the financial condition of the Parent Company on a stand-alone basis, see Note 20 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 Delaware limited partnership that owns and operates a diversified portfolio of energy assets. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, an interstate pipeline, natural gas gathering, processing and treating assets located in Texas, New Mexico, Arizona, Louisiana, Colorado and Utah, and three natural gas storage facilities located in Texas. ETP’s intrastate and interstate pipeline systems transport natural gas from several natural gas producing areas, including the Barnett Shale in the Fort Worth Basin in North Texas, the Bossier Sands in East Texas, the Permian Basin in West Texas and New Mexico, the San Juan Basin in New Mexico and other producing areas in South Texas and Central Texas. ETP’s gathering and processing operations are conducted in many of these same producing areas as well as in the Piceance and Uinta Basins in Colorado and Utah. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

 

•

Regency is a publicly-traded Delaware limited partnership, formed in 2005, engaged in the gathering, treating, processing, compressing and transporting of natural gas and NGLs. Regency provides these services through systems located in Louisiana, Texas, Arkansas, Pennsylvania and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma. Regency’s midstream assets are primarily located in well-established areas of natural gas production that have been characterized by long-lived, predictable reserves.

Preparation of Interim Financial Statements

The accompanying condensed consolidated balance sheet as of December 31, 2009, which has been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of the Partnership, as of September 30, 2010 and for the three and nine months ended September 30, 2010 and 2009, 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, 2010, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2010 and 2009. The unaudited interim condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the SEC on February 24, 2010.

Certain prior period amounts have been reclassified to conform to the 2010 presentation. These reclassifications had no impact on net income or total equity.

 

2.	ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES:

Use of 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.

 

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

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, allowances for doubtful accounts, 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, estimates related to our unit-based compensation plans, deferred taxes, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Significant Accounting Policies

As a result of the Regency Transactions on May 26, 2010, the following significant accounting policies changed as compared to the significant accounting policies described in our Form 10-K for the year ended December 31, 2009.

Revenue Recognition

In addition to the policy in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, Regency provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput and cash flow. Regency is responsible for the installation and ongoing operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. Revenues for compression services are recognized when the service is performed.

Preferred Equity

As discussed in Note 11, we issued Preferred Units in May 2010. Based on the rights associated with those securities, the Preferred Units are reflected as non-current liabilities on our condensed consolidated balance sheet, and distributions on these units are reflected in consolidated interest expense.

Regency also has outstanding convertible preferred units (the “Regency Preferred Units”), as discussed in Note 11, which were issued prior to the Regency Transactions. Based on the rights associated with those securities, the Regency Preferred Units are reflected as temporary equity on our condensed consolidated balance sheet, and distributions on these units are recorded as a reduction of the noncontrolling interest related to Regency.

 

3.	ACQUISITIONS AND DISPOSITIONS:

Regency Transactions

On May 26, 2010, we completed the Regency Transactions as discussed in Note 1. As of September 30, 2010, we owned approximately 19% of Regency’s outstanding common units, and distributions that we receive from Regency provide us with diversified cash flows and enhance our ability to increase distributions over time by pursuing new growth opportunities.

We accounted for the Regency Transactions using the purchase method of accounting. The purchase price was $305.0 million, which was the fair value of the 3,000,000 Preferred Units exchanged in connection with the Regency Transactions.

 

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The following summarizes the assets acquired and liabilities assumed in the Regency Transactions, as well as the fair value of the noncontrolling interest in Regency:

 

Total current assets		$	189,502
Property, plant and equipment (1)			1,548,384
Advances to and investments in affiliates			739,164
Goodwill			789,789
Intangible assets			666,360
Other assets			37,693
			3,970,892
Total current liabilities			192,788
Long-term debt			1,239,863
Other long-term liabilities (2)			57,517
Regency convertible preferred units			70,793
Noncontrolling interest			2,104,981
			3,665,942
Total consideration			304,950
Cash received			23,995
Total consideration, net of cash received		$	280,955

 

(1)

Property, plant and equipment consists of the following:

 

Gathering and transmission systems (5 to 20 years), including capital leases of $3.0 million		$	471,169
Compression equipment (10 to 30 years)			745,838
Gas plants and buildings (15 to 35 years)			116,967
Other property, plant and equipment (3 to 10 years)			100,264
Construction work-in-process			114,146
Property, plant and equipment		$	1,548,384

 

(2)

Liabilities assumed include capital leases of $3.1 million.

See disclosure of the amount of Regency’s revenues and earnings included in the condensed consolidated statement of operations from the close of the acquisition through September 30, 2010 in Note 19.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2010 and 2009 are presented as if the Regency Transactions had been completed on January 1, 2009. Actual results for the three months ended September 30, 2010 include Regency for the entire period.

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
Revenues		$	1,587,807			$	1,357,001			$	5,325,977			$	4,634,638
Net income (loss)			(4,826	)			13,132				219,180				567,834
Net income (loss) attributable to partners			(15,337	)			30,803				167,079				299,727
Basic net income (loss) per Limited Partner unit			(0.07	)			0.14				0.75				1.34
Diluted net income (loss) per Limited Partner unit			(0.07	)			0.14				0.75				1.34

 

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The pro forma consolidated results of operations include adjustments to:

 

•

include the results of Regency for all periods presented;

 

•

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

 

•

adjust for one-time expenses related to the Regency Transactions; and

 

•

adjust for the relative change in ownership of ETP as a result of the transfer of MEP.

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.

Other Acquisitions

In March 2010, ETP purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150.0 million in cash, excluding certain adjustments as defined in the purchase agreement. In connection with this transaction, ETP recorded customer contracts of $68.2 million and goodwill of $27.3 million. See further discussion at Note 6.

In September 2010, Regency completed its acquisition of Zephyr Gas Services, LLC, a Texas based field services company for approximately $193.3 million in cash. In connection with this transaction, Regency recorded intangible assets of $110.8 million and no goodwill.

Dispositions

In July 2010, Regency sold its East Texas gathering and processing assets to an affiliate of Tristream Energy LLC for approximately $70 million in cash. The net income from these assets is classified as discontinued operations in the condensed consolidated statements of operations from the date of the Regency Transactions to the date of the sale.

 

4.	CASH, CASH EQUIVALENTS AND SUPPLEMENTAL CASH FLOW INFORMATION:

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

 

		Nine Months Ended September 30,
		2010				2009
Net income		$	178,776			$	455,775
Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in affiliate			52,620				—
Payments for termination of Parent Company interest rate derivatives (see Note 16)			(168,550	)			—
Proceeds from termination of ETP interest rate derivatives (see Note 16)			26,495				—
Depreciation and amortization			304,681				239,626
Amortization of finance costs charged to interest			13,299				11,623
Non-cash unit-based compensation expense			22,547				21,356
Non-cash executive compensation expense			938				938
Losses on disposal of assets			408				1,333
Allowance for equity funds used during construction			(18,039	)			(18,618	)
Distributions in excess of (less than) equity in earnings of affiliates, net			71,026				(5,696	)
Other non-cash			12,678				4,884
Changes in operating assets and liabilities, net of effects of acquisitions			430,804				10,200
Net cash provided by operating activities		$	927,683			$	721,421

Non-cash investing and financing activities are as follows:

 

		Nine Months Ended September 30,
		2010				2009
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures		$	83,834			$	64,530
Gain from subsidiary issuances of common units to noncontrolling interests (recorded in partners’ capital)		$	343,714			$	46,078
NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions		$	1,240,481			$	17,113

 

5.	INVENTORIES:

Inventories consisted of the following:

 

		September 30, 2010				December 31, 2009
Natural gas and NGLs, excluding propane		$	96,498			$	157,103
Propane			57,018				66,686
Appliances, parts and fittings and other			127,993				166,165
Total inventories		$	281,509			$	389,954

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

 

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6.	GOODWILL, INTANGIBLES AND OTHER ASSETS:

A net increase in goodwill of $817.1 million was recorded during the nine months ended September 30, 2010, primarily due to $789.8 million from the Regency Transactions. This additional goodwill is not expected to be deductible for tax purposes. In addition, ETP recorded $27.3 million from the acquisition of a natural gas gathering company, which is expected to be deductible for tax purposes. See further discussion of acquisitions in Note 3.

We recorded the following intangible assets in conjunction with the Regency Transactions:

 

Amortizable intangible assets:
Customer relationships, contracts and agreements (30 years)		$	600,860
Trade names (20 years)			65,500
Total intangible and other assets acquired		$	666,360

In connection with the acquisition a natural gas gathering company, ETP also recorded customer contracts of $68.2 million with useful lives of 46 years. In connection with the Zephyr acquisition, Regency recorded intangibles related to customer relationships of $110.8 million with useful lives of 20 years.

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

 

		September 30, 2010								December 31, 2009
		Gross Carrying Amount				Accumulated Amortization				Gross Carrying Amount				Accumulated Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46 years)		$	956,456			$	(77,762	)		$	176,858			$	(58,761	)
Trade names (20 years)			65,500				(1,092	)			—				—
Noncompete agreements (3 to 15 years)			21,592				(11,965	)			24,139				(12,415	)
Patents (9 years)			750				(97	)			750				(35	)
Other (10 to 15 years)			1,320				(464	)			478				(397	)
Total amortizable intangible assets			1,045,618				(91,380	)			202,225				(71,608	)
Non-amortizable intangible assets — Trademarks			76,086				—				75,825				—
Total intangible assets			1,121,704				(91,380	)			278,050				(71,608	)
Other assets:
Financing costs (3 to 30 years)			133,319				(38,516	)			84,099				(34,702	)
Regulatory assets			107,233				(13,476	)			101,879				(9,501	)
Other			36,554				(310	)			41,466				—
Total intangibles and other assets		$	1,398,810			$	(143,682	)		$	505,494			$	(115,811	)

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
Reported in depreciation and amortization		$	10,770			$	6,243			$	23,826			$	15,935
Reported in interest expense		$	6,980			$	2,877			$	13,625			$	8,306

 

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

 

Years Ending December 31:
2011		$	58,929
2012			55,344
2013			49,913
2014			48,903
2015			46,448

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 2010 and have not recorded any impairments related to amortizable intangible assets during the nine months ended September 30, 2010.

 

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 long-term debt at September 30, 2010 was $9.86 billion and $8.84 billion, respectively. At December 31, 2009, the aggregate fair value and carrying amount of long-term debt was $8.25 billion and $7.79 billion, respectively.

We have marketable securities, commodity derivatives, interest rate derivatives and embedded derivatives in the Regency Preferred Units that are accounted for as assets and liabilities at fair value in our condensed consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. The fair value of the Preferred Units was determined by a Monte Carlo simulation 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, 2010 and December 31, 2009 based on inputs used to derive their fair values:

 

		Fair Value Measurements at September 30, 2010 Using
		Fair Value Total				Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)				Significant Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Assets:
Marketable securities		$	2,270			$	2,270			$	—			$	—
Interest rate derivatives			201				—				201				—
Commodity derivatives:
Natural Gas:
Fixed Swaps/Futures			41,656				36,992				4,664				—
Options — Puts			29,025				—				29,025				—
NGLs — Forward Swaps			9,542				—				9,542				—
WTI Crude Oil			2,505				—				2,505				—
Total commodity derivatives			82,728				36,992				45,736				—
Total Assets		$	85,199			$	39,262			$	45,937			$	—
Liabilities:
Interest rate derivatives		$	(16,307	)		$	—			$	(16,307	)		$	—
Series A Convertible Preferred Units			(304,950	)			—				—				(304,950	)
Regency Preferred Units			(44,918	)			—				—				(44,918	)
Commodity derivatives:
Natural Gas:
Basic Swaps IFERC/NYMEX			(1,153	)			(1,153	)			—				—
Swing Swaps IFERC			(937	)			(912	)			(25	)			—
Options — Calls			(1,576	)			—				(1,576	)			—
WTI Crude Oil			(877	)			—				(877	)			—
NGLs — Forward Swaps			(4,206	)			—				(4,206	)			—
Total commodity derivatives			(8,749	)			(2,065	)			(6,684	)			—
Total Liabilities		$	(374,924	)		$	(2,065	)		$	(22,991	)		$	(349,868	)

 

		Fair Value Measurements at December 31, 2009 Using
		Fair Value Total				Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)				Significant Observable Inputs (Level 2)
Assets:
Marketable securities		$	6,055			$	6,055			$	—
Commodity derivatives			32,479				20,090				12,389
Liabilities:
Commodity derivatives			(8,016	)			(7,574	)			(442	)
Interest rate derivatives			(138,036	)			—				(138,036	)
		$	(107,518	)		$	18,571			$	(126,089	)

 

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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, 2010:

 

Balance, December 31, 2009		$	—
Issuance of Series A Convertible Preferred Units			304,950
Subsidiary preferred units (recorded in connection with the Regency Transactions)			48,633
Net unrealized losses included in other income (expense)			(3,715	)
Balance, September 30, 2010		$	349,868

Prior to the Regency Transactions, ETP adjusted the investment in MEP to fair value based on the present value of expected future cash flows (Level 3), resulting in a nonrecurring fair value adjustment of $52.6 million. See Note 8.

 

8.	INVESTMENTS IN AFFILIATES:

Midcontinent Express Pipeline LLC

Certain of our subsidiaries are party to an agreement with Kinder Morgan Energy Partners, L.P. (“KMP”) for a 50/50 joint development of the Midcontinent Express pipeline. Construction of the approximately 500-mile pipeline was completed and natural gas transportation service commenced August 1, 2009, on the pipeline from Delhi, Louisiana, to an interconnect with the Transco interstate natural gas pipeline near Butler, Alabama. Interim service began on the pipeline from Bennington, Oklahoma, to Delhi in April 2009.

On January 9, 2009, MEP filed an amended application to revise its initial transportation rates to reflect an increase in projected costs for the project; the amended application was approved by the Federal Energy Regulatory Commission (“FERC”) on March 25, 2009. In May 2010, MEP, the entity formed to construct, own and operate this pipeline, placed into service certain expansion facilities to increase the total capacity for the main segment of the pipeline from Bennington to an interconnect location with Columbia Gas Transmission, LLC near Waverly, Louisiana from 1.4 Bcf/d to 1.5 Bcf/d. In June 2010, MEP placed additional expansion facilities into service, further increasing the capacity for the main segment of the pipeline from Bennington to the interconnect with the Columbia Gas Transmission pipeline from 1.5 Bcf/d to 1.8 Bcf/d, and increasing the total capacity of the main segment of the pipeline from the interconnect with Columbia Gas Transmission’s pipeline to the Transco interstate natural gas pipeline near Butler, Alabama, from 1.0 Bcf/d to 1.2 Bcf/d.

In conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of approximately 12.3 million ETP Common Units that were previously held by the Parent Company. The Parent Company immediately contributed this 49.9% interest in MEP to Regency in exchange for approximately 26.3 million Regency Common Units. In addition to the 49.9% interest in MEP, the Parent Company also acquired an option to purchase ETP’s remaining 0.1% interest in MEP in May 2011, which the Parent Company also transferred to Regency.

In conjunction with this transfer, 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 in MEP to its estimated fair value.

The following table presents aggregated selected income statement data for ETP and Regency’s unconsolidated affiliate, MEP (on a 100% basis):

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
Revenue		$	56,997			$	38,157			$	162,088			$	48,463
Operating income			29,100				18,271				76,278				21,047
Net income			16,351				14,077				42,063				15,475

As stated above, the Midcontinent Express pipeline was placed into service during 2009.

 

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RIGS Haynesville Partnership Co.

Regency owns a 49.99% interest in the RIGS Haynesville Partnership Co. joint venture (“HPC”), which, through its ownership of the Regency Intrastate Gas System (“RIGS”), delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450-mile intrastate pipeline system.

The following table presents selected income statement data for HPC (on a 100% basis):

 

		Three Months Ended September 30,								Nine Months Ended September 30,				From Inception (March 18, 2009) to September 30,
		2010				2009				2010				2009
Revenue		$	49,409			$	14,188			$	128,973			$	30,095
Operating income			30,507				8,486				74,923				12,935
Net income			30,366				9,018				74,640				14,079

Fayetteville Express Pipeline LLC

ETP is party to an agreement with KMP for a 50/50 joint development of the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that will originate in Conway County, Arkansas, continue eastward through White County, Arkansas and terminate at an interconnect with Trunkline Gas Company in Panola County, Mississippi. In December 2009, Fayetteville Express Pipeline LLC (“FEP”), the entity formed to construct, own and operate this pipeline, received FERC approval of its application for authority to construct and operate this pipeline. In July 2010, FERC granted a rehearing of the December 2009 order and allowed FEP to include in its initial rate proposed allowance for funds used during construction that accrued prior to filing its application. The pipeline began interim service in October 2010 and is expected to be fully operational in December 2010. Upon completion of all facilities, the pipeline is expected to have an initial capacity of 2.0 Bcf/d. As of September 30, 2010, FEP has secured binding commitments for a minimum of 10 years for transportation of approximately 1.85 Bcf/d. The new pipeline will interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi and ANR Pipeline Company in Quitman County, Mississippi. NGPL is operated and partially owned by Kinder Morgan, Inc. Kinder Morgan, Inc. owns the general partner of KMP.

 

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9.	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,
		2010				2009				2010				2009
Basic Net Income (Loss) per Limited Partner Unit:
Limited Partners’ interest in net income (loss)		$	(15,289	)		$	46,824			$	116,346			$	301,944
Weighted average Limited Partner units			222,941,172				222,898,248				222,941,151				222,898,188
Basic net income (loss) per Limited Partner unit		$	(0.07	)		$	0.21			$	0.52			$	1.35
Diluted Net Income (Loss) per Limited Partner Unit:
Limited Partners’ interest in net income (loss)		$	(15,289	)		$	46,824			$	116,346			$	301,944
Dilutive effect of equity-based compensation of subsidiaries			—				—				(158	)			(428	)
Diluted net income (loss) available to Limited Partners		$	(15,289	)		$	46,824			$	116,188			$	301,516
Weighted average Limited Partner units			222,941,172				222,898,248				222,941,151				222,898,188
Diluted net income (loss) per Limited Partner unit		$	(0.07	)		$	0.21			$	0.52			$	1.35

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

 

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10.	DEBT OBLIGATIONS:

Our debt obligations consisted of the following:

 

 

(1)

Excludes $19.2 million in unamortized premiums, discounts and fair value adjustments related to interest rate swaps.

Senior Notes

In addition to the ETP Senior Notes disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009, we and our subsidiaries have the following notes outstanding.

ETE Senior Notes

In September 2010, the Parent Company completed a public offering of $1.8 billion aggregate principal amount of 7.5% Senior Notes due October 15, 2020. We used net proceeds of approximately $1.77 billion to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate the interest rate swap agreements related to those borrowings, and for general partnership purposes. We may redeem some or all of the notes at any 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

Senior Notes due 2018. Subsequent to September 30, 2010, Regency completed a public offering of $600.0 million aggregate principal amount of its 6.875% Senior Notes due 2018. The sale of the notes closed on October 27, 2010 and Regency will use the net proceeds to fund the tender offer discussed below and to reduce outstanding borrowings under its revolving credit facility.

 

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Senior Notes due 2016. Regency has $250.0 million of senior notes that mature on June 1, 2016. The senior notes bear interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. The carrying value of the senior notes as of September 30, 2010 was $256.3 million, including an unamortized premium related to the Regency Transactions of $6.3 million.

At any time before June 1, 2012, up to 35% of the senior notes can be redeemed with the proceeds of an equity offering at a price of 109.375% plus accrued interest. Beginning June 1, 2013, Regency may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, Regency may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined in the indenture governing the senior notes) as of such redemption date plus 0.50% over the principal amount of the note.

Senior Notes due 2013. Regency has $357.5 million senior notes that mature on December 15, 2013. The senior notes bear interest at 8.375% and interest is payable semi-annually in arrears on each June 15 and December 15. The carrying value of the senior notes as of September 30, 2010 was $364.0 million, including an unamortized premium related to the Regency Transactions of $6.5 million.

On October 13, 2010, Regency announced that it commenced a cash tender offer and consent solicitation for its outstanding 8.375% senior notes due 2013 (the “Tender Offer”). On October 27, 2010, Regency accepted for purchase approximately $271.1 million of its senior notes due 2013 pursuant to the Tender Offer. The Tender Offer will expire 8:00 a.m., New York City time, on November 10, 2010. Regency currently anticipates that it will call for redemption any senior notes due 2013 not purchased in the Tender Offer and will satisfy and discharge the indenture relating to the senior notes due 2013 in compliance with the terms of the notes, the indenture and applicable law; provided, however, that it may elect not to redeem such notes or satisfy and discharge the related indenture.

Upon a change of control, each of Regency’s senior notes may, at such Unitholder’s option, 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. Subsequent to the Regency Transactions, no noteholder has exercised this option.

Revolving Credit Facilities

ETE Senior Secured Revolving Credit Facilities

Concurrent with the closing of its senior notes offering in September 2010, the Parent Company terminated its $500 million senior secured revolving credit facility and entered into a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. As of September 30, 2010, there were no outstanding borrowings under the Parent Company Credit Agreement.

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

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

 

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

ETP Credit Facility

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

As of September 30, 2010, there were no outstanding borrowings under the ETP Credit Facility. Taking into account letters of credit of approximately $22.4 million, the amount available for future borrowings was $1.98 billion.

Regency Credit Facility

Regency maintains its revolving credit facility (the “Regency Credit Facility”) through its subsidiary, Regency Gas Services LP (“RGS”). The Regency Credit Facility has aggregate revolving commitments of $900 million, with $200 million of availability for letters of credit. RGS 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; however, the maturity date will be accelerated to June 15, 2013 if Regency’s senior notes due 2013 have not been redeemed or refinanced by that date.

The alternate base rate used to calculate interest on base rate loans will be calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.50%. 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 0.500% based upon the consolidated leverage ratio of Regency. RGS must also pay a participation fee for each revolving lender participating in letters of credit based upon the applicable margin, which is currently 2.9% of the average daily amount of such lender’s letter of credit exposure, and a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of the letter of credit exposure.

As of September 30, 2010, there was a balance outstanding in the Regency Credit Facility of $375.0 million in revolving credit loans and approximately $16.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2010, which is reduced by any letters of credit, was approximately $509.0 million. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 3.2%.

HOLP Credit Facility

Heritage Operating, L.P. (“HOLP”), a subsidiary of ETP, has a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available to HOLP through June 30, 2011, which may be expanded to $150.0 million. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the credit agreement for the HOLP Credit Facility, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration

 

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accounts of HOLP and the capital stock of HOLP’s subsidiaries secure the HOLP Credit Facility. At September 30, 2010, the HOLP Credit Facility had no outstanding balance in revolving credit loans and outstanding letters of credit of $0.5 million. The amount available for borrowing as of September 30, 2010 was $74.5 million.

Covenants Related to Our Credit Agreements

ETP has debt covenants disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009. Additionally, Regency has its own credit agreements and a brief description of the primary covenants in its credit agreements and our updated debt covenants is set forth below. We, ETP and Regency were in compliance with all requirements, tests, limitations, and covenants related to our respective debt agreements at September 30, 2010.

Covenants Related to ETE Senior Secured Credit Facility

The Parent Company Credit Agreement contains customary representations, warranties and covenants, including financial covenants regarding a maximum leverage ratio, a maximum consolidated leverage ratio, a minimum fixed charge coverage ratio and a minimum loan to value ratio. In addition, the Parent Company Credit Agreement contains customary events of default, including, but not limited to, (i) default for failure to pay the principal on any Loan or any reimbursement obligation with respect to any letter of credit when due and payable, (ii) failure to duly observe, perform or comply with certain specified covenants, (iii) a representation or warranty made in connection with any loan document proves to have been false or incorrect in any material respect on any date on or as of which made, and (iv) the occurrence of a change of control.

Covenants Related to the Regency Senior Notes

The Regency senior 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.

If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to many of the foregoing covenants.

Covenants Related to the Regency Credit Facility

The Regency Credit Facility contains the following financial covenants:

 

•

Regency’s consolidated total leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.25 to 1.

 

•

Regency’s interest coverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not be less than 2.75 to 1.

 

•

Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.00 to 1.

On May 26, 2010, in connection with the Regency Transactions, Regency amended the Regency Credit Facility to permit its acquisition of a 49.9% membership interest in MEP and to include the results of operations of MEP in the calculation of Regency’s compliance with these financial covenants.

 

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The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:

 

•

incur indebtedness;

 

•

grant liens;

 

•

enter into sale and leaseback transactions;

 

•

make certain investments, loans and advances;

 

•

dissolve or enter into a merger or consolidation;

 

•

enter into asset sales or make acquisitions;

 

•

enter into transactions with affiliates;

 

•

prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);

 

•

issue capital stock or create subsidiaries; or

 

•

engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.

 

11.	REDEEMABLE PREFERRED UNITS

ETE Preferred Units

In connection with the Regency Transactions as discussed in Note 1, ETE issued 3,000,000 Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300.0 million and were reflected as a long-term liability in our condensed consolidated balance sheet as of September 30, 2010. The Preferred Units were issued in a private placement at a stated price of $100 per unit and are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit. The Preferred Units will automatically convert on the fourth anniversary of the date of issuance into an amount of ETE Common Units equal in value to the issue price plus any accrued but unpaid distributions plus a specified premium equal to the lesser of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance of the Preferred Units. ETE may choose, at its sole option, to pay 50% of the conversion consideration based on the issue price plus any accrued but unpaid distributions in cash. ETE may elect to redeem all, but not less than all, of the Preferred Units beginning on the third anniversary of the date of issuance for ETE Common Units or cash equal to the issue price plus a premium paid out in common units, equal to the greater of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance. GE EFS also has certain rights to force ETE to redeem or convert the outstanding Preferred Units for specified consideration upon the occurrence of certain extraordinary events involving ETE or ETP. Holders of the Preferred Units have no voting rights, except that approval of a majority of the Preferred Units is needed to approve any amendment to ETE’s Third Amended and Restated Agreement of Limited Partnership, as amended (the “Partnership Agreement”) that would result in (i) any increase in the size of the class of Preferred Units, (ii) any alteration or change to the rights, preferences, privileges, duties, or obligations of the Preferred Units or (iii) any other matter that would adversely affect the rights or preferences of the Preferred Units, including in relation to other classes of ETE partnership interests.

Regency Preferred Units

Regency has 4,371,586 Regency Preferred Units outstanding. As of September 30, 2010, the Regency Preferred Units were convertible into 4,584,192 Regency Common Units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed Regency quarterly cash distributions of $0.445 per unit. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s partnership agreement.

Upon a change in control, each unitholder may, at such holder’s option, require Regency to purchase the Regency Preferred Units for an amount equal to 101% of the total of the face value of the Regency Preferred Units plus all accrued but unpaid distributions thereon. Subsequent to the Regency Transactions, no unitholder has exercised this option.

 

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

 

		Regency Preferred Units				Amount (1)
Balance at acquisition date			4,371,586			$	70,793
Accretion to redemption value			—				103
Ending balance as of September 30, 2010			4,371,586			$	70,896

 

(1)

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

 

12.	PARTNERS’ CAPITAL:

Common Units Issued

The change in ETE Common Units during the nine months ended September 30, 2010 was as follows:

 

		Number of Units
Balance, December 31, 2009			222,898,248
Issuance of restricted common units under long-term incentive plans			42,924
Balance, September 30, 2010			222,941,172

Sale of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Regency and the underlying book value arising from issuance of units by ETP or Regency (excluding unit issuances to the Parent Company) as a capital transaction. If ETP or Regency issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether its investment has been impaired, in which case a provision would be reflected in the statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP or Regency Common Units during the nine months ended September 30, 2010.

As a result of ETP’s and Regency’s issuances and redemption of Common Units, we have recognized increases in partners’ capital of $343.7 million for the nine months ended September 30, 2010.

Sale of Common Units by ETP

In January 2010, ETP issued 9,775,000 ETP Common Units through a public offering for net proceeds of $423.6 million. In August 2010, ETP issued 10,925,000 Common Units through a public offering for net proceeds of $489.4 million. The proceeds from these offerings were used primarily to repay borrowings under the ETP Credit Facility and to fund capital expenditures related to pipeline projects.

On August 26, 2009, ETP entered into an Equity Distribution Agreement with UBS Securities LLC (“UBS”). Pursuant to this agreement, ETP may offer and sell from time to time through UBS, as their sales agent, ETP Common Units having an aggregate value of up to $300.0 million. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between ETP and UBS. Under the terms of this agreement, ETP may also sell ETP Common Units to UBS as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to UBS as principal would be pursuant to the terms of a separate agreement between ETP and UBS. During the nine months ended September 30, 2010, ETP issued 3,842,283 ETP Common Units pursuant to this agreement. The proceeds of approximately $174.1 million, net of commissions, were used for general partnership purposes. Approximately $40.6 million of ETP’s Common Units remain available to be issued under the agreement based on trades initiated through September 30, 2010.

 

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On May 26, 2010, in conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of 12,273,830 ETP Common Units that were previously held by the Parent Company (see Note 8).

Sale of Common Units by Regency

In August 2010, Regency issued 17,537,500 Regency Common Units through a public offering. The proceeds of $400.2 million from the offering were used primarily to repay borrowings under the Regency Credit Facility.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. 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.

Distributions paid by the Parent Company are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per Common Unit
December 31, 2009		February 8, 2010		February 19, 2010		$	0.54
March 31, 2010		May 7, 2010		May 19, 2010			0.54
June 30, 2010		August 9, 2010		August 19, 2010			0.54

On October 28, 2010, the Parent Company announced the declaration of a cash distribution for the three months ended September 30, 2010 of $0.54 per Common Unit, or $2.16 annualized. This distribution will be paid on November 19, 2010 to Unitholders of record at the close of business on November 8, 2010.

The total amounts of distributions declared during the nine months ended September 30, 2010 and 2009 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,
		2010				2009
Limited Partners		$	361,164			$	355,523
General Partner			1,122				1,104
Total distributions declared		$	362,286			$	356,627

ETP’s Quarterly Distributions of Available Cash

ETP is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner.

Distributions paid by ETP are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per Common Unit
December 31, 2009		February 8, 2010		February 15, 2010		$	0.89375
March 31, 2010		May 7, 2010		May 17, 2010			0.89375
June 30, 2010		August 9, 2010		August 16, 2010			0.89375

On October 28, 2010, ETP declared a cash distribution for the three months ended September 30, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on November 15, 2010 to Unitholders of record at the close of business on November 8, 2010.

 

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The total amounts of ETP distributions declared during the nine months ended September 30, 2010 and 2009 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,
		2010				2009
Limited Partners:
Common Units		$	503,582			$	460,132
Class E Units			9,363				9,363
General Partner Interest			14,634				14,626
Incentive Distribution Rights			279,823				256,530
Total distributions declared by ETP		$	807,402			$	740,651

Regency’s Quarterly Distributions of Available Cash

Regency is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner.

Distributions paid by Regency are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per Common Unit
June 30, 2010		August 6, 2010		August 13, 2010		$	0.445

On October 26, 2010, Regency declared a cash distribution for the three months ended September 30, 2010 of $0.445 per Common Unit, or $1.78 annualized. This distribution will be paid on November 12, 2010 to Unitholders of record at the close of business on November 5, 2010.

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

 

		Nine Months Ended September 30,
		2010				2009
Limited Partners		$	114,270			$	—
General Partner Interest			2,372				—
Incentive Distribution Rights			1,965				—
Total distributions declared by Regency		$	118,607			$	—

Accumulated Other Comprehensive Income (Loss)

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

 

		September 30, 2010				December 31, 2009
Net gains on commodity related hedges		$	43,270			$	1,991
Net losses on interest rate hedges			—				(56,210	)
Unrealized gains on available-for-sale securities			1,157				4,941
Noncontrolling interest			(32,196	)			(4,350	)
Total AOCI, net of tax		$	12,231			$	(53,628	)

 

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13.	UNIT-BASED COMPENSATION PLANS:

No significant activity has occurred with respect to the ETE Long-Term Incentive Plan or ETP’s unit-based compensation plans during the nine months ended September 30, 2010.

Regency has the following awards outstanding as of September 30, 2010:

 

•

286,850 Regency common unit options, all of which are exercisable, with a weighted average exercise price of $21.55 per unit option;

 

•

No Regency restricted (non-vested) common units; and

 

•

200,267 Regency phantom units, with a weighted average grant date fair value of $15.43 per phantom unit.

In conjunction with the Regency Transactions, certain of Regency’s then-outstanding phantom units converted to 252,630 Regency Common Units as a result of change-in-control provisions associated with the awards. Each of Regency’s outstanding phantom units as of September 30, 2010 is the economic equivalent of one Regency Common Unit and is accompanied by a Distribution Equivalent Right, entitling the holder to an amount equal to any cash distributions paid on Regency Common Units. The outstanding Regency phantom units will vest one-third on each March 15th through 2013.

Regency expects to recognize $2.9 million of compensation expense related to the Regency phantom units over a weighted average period of 2.5 years.

 

14.	INCOME TAXES:

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
Current expense (benefit):
Federal		$	(3,182	)		$	(88	)		$	(124	)		$	(5,195	)
State			1,363				3,224				8,864				10,120
Total			(1,819	)			3,136				8,740				4,925
Deferred expense (benefit):
Federal			3,286				(6,394	)			2,257				1,299
State			626				(439	)			360				(451	)
Total			3,912				(6,833	)			2,617				848
Total income tax expense (benefit)		$	2,093			$	(3,697	)		$	11,357			$	5,773
Effective tax rate			(68.47	%)			(12.09	%)			5.99	%			1.25	%

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.

 

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

Regulatory Matters

In August 2009, ETP filed an application for FERC authority to construct and operate the Tiger pipeline. The application was approved in April 2010 and construction began in June 2010. Subject to regulatory approvals, we expect initial service on the Tiger pipeline to commence in the fourth quarter of 2010. In February 2010, ETP announced a 400 MMcf/d expansion of the Tiger pipeline. In June 2010, we filed an application requesting FERC authorization to construct, own and operate that expansion, which remains under review before the FERC.

 

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On September 29, 2006, 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. Transwestern’s tariff rates and fuel rates are now final for the period of the settlement. Transwestern Pipeline Company, LLC (“Transwestern”), a subsidiary of ETP, is required to file a new rate case no later than October 1, 2011.

Guarantees

MEP Guarantee

ETP has guaranteed 50% of the obligations of MEP under its senior revolving credit facility (the “MEP Facility”), with the remaining 50% of MEP Facility obligations guaranteed by KMP. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions. Although ETP transferred substantially all of its interest in MEP on May 26, 2010, as discussed above in Note 1, ETP will continue to guarantee 50% of MEP’s obligations under this facility through the maturity of the facility in February 2011. Regency has agreed to indemnify ETP for any costs related to the guarantee of payments under this facility.

Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage in MEP increases or decreases. The MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

As of September 30, 2010, MEP had $82.2 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. Our contingent obligations with respect to the 50% guarantee of MEP’s outstanding borrowings and letters of credit were $41.1 million and $16.6 million, respectively, as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 0.9%.

FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP has guaranteed 50% of the obligations of FEP under the FEP Facility, with the remaining 50% of FEP Facility obligations guaranteed by KMP. Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012 and amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the FEP Facility varies based on both ETP’s credit rating and that of KMP, with a maximum fee of 1.0%.

As of September 30, 2010, FEP had $847.0 million of outstanding borrowings issued under the FEP Facility. ETP’s contingent obligation with respect to our 50% guarantee of FEP’s outstanding borrowings was $423.5 million as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 3.3%.

Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts. In addition, we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We have 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. We also have a contract to purchase not less than 90.0 million gallons of propane per year that expires in 2015. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

 

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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $6.0 million for the three months ended September 30, 2010 and 2009. For the nine months ended September 30, 2010 and 2009, rental expense for operating leases totaled approximately $17.7 million and $17.5 million, respectively.

Future minimum lease commitments for leases are:

 

Years Ending December 31:
2010 (remainder)		$	14,999
2011			27,327
2012			25,095
2013			22,419
2014			20,668
Thereafter			224,538

ETP’s propane operations have an agreement with a subsidiary of Enterprise GP Holdings L.P. (collectively “Enterprise”) (see Note 17) to supply a portion of its propane requirements. The agreement expired in March 2010; however, ETP’s propane operations executed a five year extension as of April 2010. The extension will continue until March 2015 and includes an option to extend the agreement for an additional year.

ETP and Regency have commitments to make capital contributions to joint ventures. For the joint ventures that ETP currently has interests in, it expects that future capital contributions will be between $10 million and $15 million, which ETP expects to contribute primarily during the last three months of 2010. In addition, Regency expects capital contributions will be $47 million during the last three months of 2010.

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.

FERC and Related Matters. On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of ETP’s index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the NGA. The FERC alleged that ETP violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. The FERC also alleged that one of ETP’s intrastate pipelines violated various FERC regulations by, among other things, granting undue preferences in favor of an affiliate. In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims. In February 2008, the FERC’s Enforcement Staff also recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005 for November 2005 monthly deliveries, a period not previously covered by the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

 

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On August 26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against ETP and, on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement resolves all outstanding FERC claims against ETP and provides that ETP make a $5.0 million payment to the federal government and establish a $25.0 million fund for the purpose of settling related third-party claims based on or arising out of the market manipulation allegation against ETP by those third parties that elect to make a claim against this fund, including existing litigation claims as well as any new claims that may be asserted against this fund. Pursuant to the settlement agreement, the FERC made no findings of fact or conclusions of law. In addition, the settlement agreement specifies that by executing the settlement agreement ETP does not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with ETP’s alleged conduct related to the FERC claims. The settlement agreement also requires ETP to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

In September 2009, the FERC appointed an administrative law judge, or ALJ, to establish a process of potential claimants to make claims against the $25.0 million fund, to determine the validity of any such claims and to make a recommendation to the FERC relating to the application of this fund to any potential claimants. Pursuant to the process established by the ALJ, a number of parties submitted claims against this fund and, subsequent thereto, the ALJ made various determinations with respect to the validity of these claims, solely for purposes of participation in this fund allocation process, and the methodology for making payments from the fund to claimants. In June 2010, each claimant that had been allocated a payment amount from the fund by the ALJ was required to make a determination as to whether to accept the ALJ’s recommended payment amount from the fund, and all such claimants accepted their allocated payment amounts. In connection with accepting the allocated payment amount, each such claimant was required to waive and release all claims against ETP related to this matter.

In addition to the claims that were settled pursuant to the ALJ fund allocation process discussed above, ETP was a party in three legal proceedings that asserted contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006. In all three of these legal proceedings, we have received favorable rulings at the lower court and appellate court levels that have resulted in the dismissal of all claims made in these proceedings, and no further appeals or motions for rehearing may be pursued by the plaintiffs in these proceedings except with respect to one proceeding as to which the plaintiffs may seek review at the U.S. Supreme Court, which action we believe is unlikely to occur.

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. ETP records accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, ETP made the $5.0 million payment and established the $25.0 million fund in October 2009. The after-tax impact of the settlement was less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims.

Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies and American Electric Power Corporation (“AEP”), were defendants in litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel storage facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas Litigation”. In 2004, ETC OLP (a subsidiary of ETP) acquired the HPL Entities from AEP, at which time AEP agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory (approximately $1.00 billion in the aggregate). The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel storage facility. Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP expects that it will be indemnified for any monetary damages awarded to B of A under this court decision.

Other Matters. In addition to those matters described above, we or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the

 

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merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As of September 30, 2010 and December 31, 2009, accruals of approximately $10.4 million and $11.1 million, respectively, were recorded related to deductibles. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and it is possible that the outcome of a particular matter will result in the payment of an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

No amounts have been recorded in our September 30, 2010 or December 31, 2009 condensed consolidated balance sheets for contingencies and current litigation matters, other than accruals related to environmental matters and deductibles.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that can require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline, gathering, treating, compressing, blending and processing business. 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. Accordingly, we have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.

ETP Environmental Matters

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in clean-up technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

As of September 30, 2010 and December 31, 2009, accruals on an undiscounted basis of $12.3 million and $12.6 million, respectively, were recorded in our condensed consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for clean-up costs.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the clean-up activities include remediation of several compressor sites on the Transwestern system for historical contamination associated with polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates.

 

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The total accrued future estimated cost of remediation activities expected to continue through 2018 is $8.3 million, which is included in the aggregate environmental accruals. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential 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.

Environmental regulations were recently modified for the U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our 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. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our September 30, 2010 condensed consolidated balance sheet or our December 31, 2009 consolidated balance sheet. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

By March 2013, the Texas Commission on Environmental Quality is required to develop another plan to address the recent change in the ozone standard from 0.08 parts per million, or ppm, to 0.075 ppm and the EPA recently proposed lowering the standard even further, to somewhere in between 0.06 and 0.07 ppm. These efforts may result in the adoption of new regulations that may require additional nitrogen oxide emissions reductions.

ETP’s pipeline operations are subject to regulation by the U.S. Department of Transportation (“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, 2010 and 2009, $5.8 million and $9.3 million, respectively, of capital costs and $3.9 million and $3.6 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. For the nine months ended September 30, 2010 and 2009, $10.8 million and $24.6 million, respectively, of capital costs and $10.2 million and $12.6 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.

Our operations are also subject to the requirements of the federal Occupational Safety and Health Act, also known as 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

 

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states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the 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.

Regency Environmental Matters

In 2004, a Phase I environmental study was performed on certain of Regency’s assets located in West Texas. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1.9 million to $3.1 million. No governmental agency has required Regency to undertake these remediation efforts. Regency believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, Regency acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10.0 million limit subject to certain deductibles. No claims have been made against Regency or under the policy. Unless a claim has been made on Regency that exceeds the limits of the insurance policy, Regency will not further report on this matter.

Regency Field Services LLC (“RFS”), one of Regency’s operating subsidiaries, currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have groundwater contamination as a result of historical operations. At the time that RFS acquired the Plants from El Paso Field Services LP (“El Paso”), Kerr-McGee Corporation (“Kerr-McGee”) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants. Tronox has thus far continued its remediation efforts at the Plants. RFS is seeking assignment of indemnity rights against Tronox from El Paso. Tronox filed a reorganization plan on July 7, 2010. The Plan calls for the creation of a trust fund environmental clean-up at the various sites where Tronox has an obligation. Tronox must file the Environmental Claims Settlement Agreement, which will set forth the amount of trust funds allocated to each site, 14 days prior to the confirmation hearing, the date for which has not yet been set.

 

16.	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

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, we 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 the condensed consolidated balance sheets. In general, our subsidiaries use derivatives to eliminate market exposure and price risk within its operations as follows:

 

•

Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility in its marketing activities and manage fixed price exposure incurred from contractual obligations. Regency also enters into swap contracts for WTI crude oil in addition to NGLs and natural gas to reduce price volatility.

 

•

ETP uses derivative financial instruments in connection with its natural gas inventory at the Bammel storage facility by purchasing physical natural gas and then selling financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. ETP also uses derivatives in its intrastate transportation and storage operations to hedge the sales price of retention gas and hedge location price differentials related to the transportation of natural gas.

 

•

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.

 

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

ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales 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 accumulated other comprehensive income until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the condensed consolidated statement of operations.

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.

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 focus. 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.

 

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The following table details the outstanding commodity-related derivatives:

 

		September 30, 2010								December 31, 2009
		Notional Volume				Maturity				Notional Volume				Maturity
Mark-to-Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)			(33,870,000	)			2010-2011				72,325,000				2010-2011
Swing Swaps IFERC (MMBtu)			11,735,000				2010-2011				(38,935,000	)			2010
Fixed Swaps/Futures (MMBtu)			486,000				2010-2011				4,852,500				2010-2011
Options — Puts (MMBtu)			440,000				2010-2011				2,640,000				2010
Options — Calls (MMBtu)			(3,440,000	)			2010-2011				(2,640,000	)			2010
Propane:
Forwards/Swaps (Gallons)			—				—				6,090,000				2010
Natural Gas Liquids:
Forwards/Swaps (Barrels)			348,000				2010				—				—
WTI Crude Oil:
Forwards/Swaps (Barrels)			59,800				2010				—				—
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)			(10,060,000	)			2010-2011				(22,625,000	)			2010
Fixed Swaps/Futures (MMBtu)			(20,160,000	)			2010-2011				(27,300,000	)			2010
Hedged Item — Inventory (MMBtu)			20,160,000				2010				27,300,000				2010
Cash Flow Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX (MMBtu)			(4,445,000	)			2010-2011				(13,225,000	)			2010
Fixed Swaps/Futures (MMBtu)			(5,440,000	)			2010-2011				(22,800,000	)			2010
Options — Puts (MMBtu)			22,680,000				2011-2012				—				—
Options — Calls (MMBtu)			(22,680,000	)			2011-2012				—				—
Propane:
Forwards/Swaps (Gallons)			58,086,000				2010-2011				20,538,000				2010
Natural Gas Liquids:
Forwards/Swaps (Barrels)			1,359,340				2011-2012				—				—
WTI Crude Oil:
Forwards/Swaps (Barrels)			249,295				2011-2012				—				—

We expect gains of $36.6 million related to 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 have previously managed a portion of our current and future interest rate exposures by utilizing interest rate swaps in order to achieve our desired mix of fixed and variable rate debt. ETP also utilizes interest rate swaps to lock in the rate on a portion of its anticipated debt issuances. Our subsidiaries have the following interest rate swaps outstanding as of September 30, 2010:

 

Entity

Term

Notional Amount

Type (1)

Hedge Designation

ETP

August 2012

$

400,000

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

Undesignated

Regency

April 2012

250,000

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

Undesignated

 

(1)

Floating rates are based on LIBOR.

In May and August 2010, ETP terminated interest rate swaps with total notional amounts of $750.0 million and $350.0 million, respectively, for proceeds of $15.4 million and $11.1 million, respectively. These swaps were designated as fair value hedges. In connection with the swap terminations, $9.7 million and $10.4 million of previously recorded fair value adjustments to hedged long-term debt will be amortized as a reduction of interest expense through February 2015 and July 2013, respectively. The unamortized balance remaining related to these swaps was $18.7 million as of September 30, 2010.

In August 2010, ETP de-designated $200.0 million of total notional amounts of forward-starting interest rate swaps previously designated as cash flow hedges. These swaps remain outstanding as of September 30, 2010, along with additional swaps with a total notional amount of $200.0 million entered into during the three months ended September 30, 2010.

In addition to interest rate swaps, ETP also periodically enters into interest rate swaptions that enable counterparties to exercise options to enter into interest rate swaps with ETP. Swaptions may be utilized when ETP’s targeted benchmark interest rate for anticipated debt issuance is not attainable at the time in the interest rate swap market. Upon issuance of a swaption, ETP receives a premium, which ETP recognizes over the term of the swaption to “Gains (losses) on non-hedged interest rate derivatives” in the condensed consolidated statements of operations. No swaptions were outstanding as of September 30, 2010. In October 2010, the Partnership sold a swaption with a notional amount of $100.0 million and maturity date of December 31, 2010 to enter into a swap that, if exercised, would lock in the rate on a portion of anticipated debt issuances.

In connection with ETE’s offering of senior notes in September 2010, ETE terminated interest rate swaps with an aggregate notional amount of $1.5 billion and recognized in interest expense $66.4 million of realized losses on terminated interest rate swaps that had been accounted for as cash flow hedges. In addition to the $66.4 million of realized losses on hedged interest rate swaps, ETE also paid $102.2 million to terminate non-hedged interest rate swaps. The $102.2 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings. The total cash paid to terminate interest rate swaps was $168.6 million, including realized losses on hedged and non-hedged swaps.

 

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Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of September 30, 2010 and December 31, 2009:

 

		Fair Value of Derivative Instruments
		Asset Derivatives								Liability Derivatives
		September 30, 2010				December 31, 2009				September 30, 2010				December 31, 2009
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)		$	57,648			$	669			$	(1,732	)		$	(24,035	)
Commodity derivatives			9,544				8,443				(4,725	)			(201	)
Interest rate derivatives			—				—				—				(61,879	)
			67,192				9,112				(6,457	)			(86,115	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)			66,113				72,851				(59,654	)			(36,950	)
Commodity derivatives			7,348				3,928				(564	)			(241	)
Interest rate derivatives			201				—				(16,307	)			(76,157	)
Embedded derivatives in Regency Preferred Units			—				—				(44,918	)			—
			73,662				76,779				(121,443	)			(113,348	)
Total derivatives		$	140,854			$	85,891			$	(127,900	)		$	(199,463	)

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

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

Regency is exposed to credit risk from its derivative counterparties. Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and enters into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

ETP utilizes master-netting agreements and have maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives, and it exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the condensed consolidated balance sheets. ETP had net deposits with counterparties of $58.7 million and $79.7 million as of September 30, 2010 and December 31, 2009, respectively.

 

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The following tables summarize the amounts recognized with respect to our 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,
		2010				2009				2010				2009
Derivatives in cash flow hedging relationships:
Commodity derivatives		$	36,035			$	(15,146	)		$	60,992			$	(15,282	)
Interest rate derivatives			(9,825	)			(12,451	)			(29,980	)			(12,289	)
Total		$	26,210			$	(27,597	)		$	31,012			$	(27,571	)

 

		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,
						2010				2009				2010				2009
Derivatives in cash flow hedging relationships:
Commodity derivatives			Cost of products sold			$	6,780			$	(847	)		$	19,153			$	8,702
Interest rate derivatives			Interest expense				(70,812	)			(7,220	)			(86,697	)			(18,927	)
Total						$	(64,032	)		$	(8,067	)		$	(67,544	)		$	(10,225	)
		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,
						2010				2009				2010				2009
Derivatives in cash flow hedging relationships:
Commodity derivatives			Cost of products sold			$	241			$	(95	)		$	346			$	(95	)
Interest rate derivatives			Interest expense				—				—				—				—
Total						$	241			$	(95	)		$	346			$	(95	)
		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,
						2010				2009				2010				2009
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives			Cost of products sold			$	9,968			$	(20,909	)		$	9,001			$	(8,411	)
Interest rate derivatives			Interest expense				—				—				—				—
Total						$	9,968			$	(20,909	)		$	9,001			$	(8,411	)

 

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		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,
				2010				2009				2010				2009
Derivatives not designated as hedging instruments:
Commodity derivatives		Cost of products sold		$	3,219			$	30,346			$	3,762			$	87,349
Interest rate derivatives		Gains (losses) on non-hedged interest rate derivatives			(31,966	)			(35,589	)			(68,858	)			24,373
Embedded Derivatives		Other income (expenses)			7,321				—				3,715				—
Total				$	(21,426	)		$	(5,243	)		$	(61,381	)		$	111,722

We recognized $0.8 million and $13.5 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the three months ended September 30, 2010 and 2009, respectively. We recognized $49.0 million and $32.7 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, 2010 and 2009, respectively. For the three and nine months ended September 30, 2009, we recognized unrealized losses of $16.4 million and $3.9 million, respectively, on commodity derivatives and related hedged inventory in fair value hedging relationships. For the three and nine months ended September 30, 2010, we recognized an unrealized gain of $8.2 million and an unrealized loss of $35.3 million, respectively, on commodity derivatives and related hedged inventory in fair value hedging relationships.

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 exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution 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. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on our 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 condensed consolidated balance sheet and recognized in net income or other comprehensive income.

 

17.	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, 2010, the Parent Company received $2.5 million and $3.3 million from Regency related to these services. For the three months ended September 30, 2010 and 2009, the Parent Company paid $2.6 million and $0.1 million, respectively, to ETP related to these services. For the nine months ended September 30, 2010 and 2009, the Parent Company paid $3.7 million and $0.4 million, respectively, to ETP related to these services.

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

ETP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ETP sells natural gas to Enterprise. ETP’s propane operations routinely buy and sell product with

 

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Enterprise. Regency sells natural gas and NGLs to, and incurs NGL processing fees with Enterprise. The following table presents sales to and purchase from Enterprise, including Regency transactions subsequent to May 26, 2010:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
ETP’s Natural Gas Operations:
Sales		$	126,992			$	118,272			$	402,238			$	283,346
Purchases			396				12,958				13,928				29,304
Regency’s Natural Gas Operations:
Sales			53,620				—				72,121				—
Purchases			1,890				—				2,312				—
ETP’s Propane Operations:
Sales			262				2,815				11,228				14,323
Purchases			58,642				44,022				276,821				220,245

ETP’s propane operations purchase a portion of its propane requirements from Enterprise pursuant to an agreement that was extended until March 2015, and includes an option to extend the agreement for an additional year. As of December 31, 2009, ETP had forward mark-to-market derivatives for 6.1 million gallons of propane at a fair value asset of $3.3 million with Enterprise. All of these forward contracts were settled as of June 30, 2010. In addition, as of September 30, 2010 and December 31, 2009, a subsidiary engaged in retail propane operations had forward derivatives accounted for as cash flow hedges of 58.1 million and 20.5 million gallons of propane at a fair value asset of $5.7 million and $8.4 million, respectively, with Enterprise.

Under a master services agreement with HPC, Regency operates and provides all employees and services for the operation and management of HPC. Under this agreement, Regency receives $1.4 million monthly as a partial reimbursement of its general and administrative costs. Regency also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. The related party general administrative expenses reimbursed to Regency were $4.2 million for the three months ended September 30, 2010 and $5.6 million for the period from May 26, 2010 to September 30, 2010.

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

 

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

 

		September 30, 2010				December 31, 2009
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations		$	35,175			$	47,005
Regency’s Natural Gas Operations			21,572				—
ETP’s Propane Operations			407				3,386
Other			4,911				1,503
Total accounts receivable from related parties:		$	62,065			$	51,894
Accounts payable to related parties:
Enterprise:
ETP’s Natural Gas Operations		$	1,561			$	3,518
Regency’s Natural Gas Operations			1,070				—
ETP’s Propane Operations			8,209				31,642
Other			2,552				3,355
Total accounts payable to related parties:		$	13,392			$	38,515

ETP’s net imbalance payable from Enterprise was $32 thousand and $0.7 million as of September 30, 2010 and December 31, 2009, respectively. Regency’s net imbalance payable with Enterprise was $0.6 million as of September 30, 2010.

 

18.	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, 2010				December 31, 2009
Deposits paid to vendors		$	58,710			$	79,694
Prepaid and other			69,633				70,018
Total other current assets		$	128,343			$	149,712

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

		September 30, 2010				December 31, 2009
Interest payable		$	142,790			$	137,708
Customer advances and deposits			128,903				88,430
Accrued capital expenditures			55,013				46,134
Accrued wages and benefits			49,145				25,577
Taxes other than income taxes			81,995				23,294
Income taxes payable			4,867				3,154
Other			87,389				42,484
Total accrued and other current liabilities		$	550,102			$	366,781

 

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19.	REPORTABLE SEGMENTS:

As a result of the Regency Transactions in May 2010, our reportable segments were reevaluated and now 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 and its general partner, ETP GP.

 

•

Investment in Regency — Reflects the consolidated operations of Regency and its general partner, Regency GP.

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 the financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

 

		Investment in ETP				Investment in Regency				Corporate and Other				Adjustments and Eliminations				Total
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	)			—
Depreciation and amortization			85,612				32,205				3,056				(558	)			120,315
Interest expense, net of interest capitalized			101,241				20,379				89,486				(1,235	)			209,871
Equity in earnings of affiliates			595				21,754				—				—				22,349
Income tax expense (benefit)			1,993				450				(350	)			—				2,093
Net income (loss)			107,387				7,846				(120,059	)			—				(4,826	)
Three months ended September 30, 2009:
Revenues from external customers		$	1,129,596			$	—			$	—			$	253			$	1,129,849
Intersegment revenues			—				—				—				—				—
Depreciation and amortization			81,684				—				3,054				—				84,738
Interest expense, net of interest capitalized			101,503				—				18,597				—				120,100
Equity in earnings of affiliates			9,581				—				—				—				9,581
Income tax expense (benefit)			(2,897	)			—				(800	)			—				(3,697	)
Net income (loss)			72,456				—				(38,189	)			—				34,267
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	)			—
Depreciation and amortization			252,765				42,750				9,166				—				304,681
Interest expense, net of interest capitalized			309,217				28,460				126,409				(3,508	)			460,578
Equity in earnings of affiliates			10,848				29,875				—				—				40,723
Income tax expense (benefit)			12,486				695				(1,824	)			—				11,357
Net income (loss)			390,341				2,951				(214,516	)			—				178,776

 

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		Investment in ETP				Investment in Regency				Corporate and Other				Adjustments and Eliminations				Total
Nine months ended September 30, 2009:
Revenues from external customers		$	3,911,513			$	—			$	—			$	—			$	3,911,513
Intersegment revenues			—				—				—				—				—
Depreciation and amortization			230,461				—				9,165				—				239,626
Interest expense, net of interest capitalized			284,228				—				56,822				—				341,050
Equity in earnings of affiliates			11,751				—				—				—				11,751
Income tax expense (benefit)			8,594				—				(2,821	)			—				5,773
Net income (loss)			530,361				—				(74,586	)			—				455,775

 

		As of September 30, 2010				As of December 31, 2009
Total assets:
Investment in ETP		$	11,714,331			$	11,734,972
Investment in Regency			4,692,722				—
Corporate and Other			452,185				431,109
Adjustments and Eliminations			(7,891	)			(5,572	)
Total		$	16,851,347			$	12,160,509
		Nine Months Ended September 30,
		2010				2009
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP		$	1,140,501			$	642,459
Investment in Regency (including $1.5 billion acquired in the Regency Transactions)			1,741,298				—
Total		$	2,881,799			$	642,459

 

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20.	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, 2010				December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	6,325			$	62
Accounts receivable from related companies			393				97
Other current assets			1,093				1,287
Total current assets			7,811				1,446
ADVANCES TO AND INVESTMENTS IN AFFILIATES			2,249,788				1,711,928
INTANGIBLES AND OTHER ASSETS, net			29,522				5,574
Total assets		$	2,287,121			$	1,718,948
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable		$	143			$	178
Accounts payable to related companies			6,663				5,024
Price risk management liabilities			—				64,704
Accrued and other current liabilities			10,966				1,607
Total current liabilities			17,772				71,513
LONG-TERM DEBT, less current maturities			1,800,000				1,573,951
SERIES A CONVERTIBLE PREFERRED UNITS			304,950				—
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES			—				73,332
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner			633				368
Limited Partners – Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at September 30, 2010 and December 31, 2009, respectively)			151,535				53,412
Accumulated other comprehensive income (loss)			12,231				(53,628	)
Total partners’ capital			164,399				152
Total liabilities and partners’ capital		$	2,287,121			$	1,718,948

 

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STATEMENTS OF OPERATIONS

(unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September  30,
		2010				2009				2010				2009
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES		$	(2,920	)		$	(786	)		$	(20,335	)		$	(3,608	)
OTHER INCOME (EXPENSE):
Interest expense			(89,484	)			(18,589	)			(126,400	)			(56,728	)
Equity in earnings of affiliates			102,388				82,661				324,128				370,195
Losses on non-hedged interest rate derivatives			(18,211	)			(17,348	)			(53,388	)			(7,954	)
Other, net			(6,736	)			957				(6,949	)			329
INCOME (LOSS) BEFORE INCOME TAXES			(14,963	)			46,895				117,056				302,234
Income tax (expense) benefit			(374	)			76				(349	)			648
NET INCOME (LOSS)			(15,337	)			46,971				116,707				302,882
GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)			(48	)			147				361				938
LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)		$	(15,289	)		$	46,824			$	116,346			$	301,944

 

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STATEMENTS OF CASH FLOWS

(unaudited)

 

		Nine Months Ended September 30,
		2010				2009
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	175,126			$	349,402
CASH FLOWS FROM INVESTING ACTIVITIES:
MEP Transaction			3,016				—
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			1,850,245				50,406
Principal payments on debt			(1,624,374	)			(48,771	)
Distributions to Partners			(362,286	)			(351,037	)
Debt issuance costs			(35,464	)			—
Net cash used in financing activities			(171,879	)			(349,402	)
INCREASE IN CASH AND CASH EQUIVALENTS			6,263				—
CASH AND CASH EQUIVALENTS, beginning of period			62				62
CASH AND CASH EQUIVALENTS, end of period		$	6,325			$	62

 

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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, 2009 filed with the SEC on February 24, 2010. Additionally, Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”) electronically file certain documents with the SEC, including annual reports on Form 10-K and quarterly reports on Form 10-Q. The SEC file number for each registrant and company website address is as follows:

 

•

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

 

•

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

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

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009.

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.

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, 2010, our equity interests consisted of:

 

		General Partner Interest				IDRs				Common Units
ETP			1.8	%			100	%			50,226,967
Regency			2.0	%			100	%			26,266,791

The principal sources of historical cash flow have been distributions we receive from our direct and indirect investments in limited and general partner interests of ETP. Distributions that we receive from Regency provide us with diversified cash flows and enhance our ability to increase distributions over time by pursuing new growth opportunities. The Parent Company’s primary cash requirements are for distributions to its partners and holders of the Preferred Units, general and administrative expenses, and debt service. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP, Regency or their respective subsidiaries.

We acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions, that were completed on May 26, 2010. In the Regency Transactions, we:

 

•

acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Series A Convertible Preferred Units having an aggregate liquidation preference of $300.0 million;

 

•

acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”), ETP’s joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) to operate the Midcontinent Express Pipeline, and an option to acquire an additional 0.1% interest in MEP in exchange for the redemption by ETP of approximately 12.3 million ETP Common Units we previously owned; and

 

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•

acquired 26.3 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.

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

 

•

ETP is a publicly-traded Delaware limited partnership that owns and operates a diversified portfolio of energy assets. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, an interstate pipeline, natural gas gathering, processing and treating assets located in Texas, New Mexico, Arizona, Louisiana, Colorado and Utah, and three natural gas storage facilities located in Texas. ETP’s intrastate and interstate pipeline systems transport natural gas from several natural gas producing areas, including the Barnett Shale in the Fort Worth Basin in North Texas, the Bossier Sands in East Texas, the Permian Basin in West Texas and New Mexico, the San Juan Basin in New Mexico and other producing areas in South Texas and Central Texas. ETP’s gathering and processing operations are conducted in many of these same producing areas as well as in the Piceance and Uinta Basins in Colorado and Utah. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

 

•

Regency is a publicly-traded Delaware limited partnership, formed in 2005, engaged in the gathering, treating, processing, compressing and transporting of natural gas and NGLs. Regency provides these services through systems located in Louisiana, Texas, Arkansas, Pennsylvania and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma. Regency’s midstream assets are primarily located in well-established areas of natural gas production that have been characterized by long-lived, predictable reserves.

Results of Operations

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

Consolidated Results

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2010				2009				Change				2010				2009				Change
Revenues		$	1,587,807			$	1,129,849			$	457,958			$	4,822,316			$	3,911,513			$	910,803
Cost of products sold			995,105				678,148				316,957				3,060,423				2,263,280				797,143
Gross margin			592,702				451,701				141,001				1,761,893				1,648,233				113,660
Operating expenses			208,809				158,883				49,926				559,302				517,337				41,965
Depreciation and amortization			120,315				84,738				35,577				304,681				239,626				65,055
Selling, general and administrative			61,526				34,579				26,947				177,673				146,640				31,033
Operating income			202,052				173,501				28,551				720,237				744,630				(24,393	)
Interest expense, net of interest capitalized			(209,871	)			(120,100	)			(89,771	)			(460,578	)			(341,050	)			(119,528	)
Equity in earnings of affiliates			22,349				9,581				12,768				40,723				11,751				28,972
Gains (losses) on disposal of assets			81				(1,088	)			1,169				(408	)			(1,333	)			925
Gains (losses) on non-hedged interest rate derivatives			(31,966	)			(35,589	)			3,623				(68,858	)			24,373				(93,231	)
Allowance for equity funds used during construction			12,432				30				12,402				18,039				18,618				(579	)
Impairment of investment in affiliate			—				—				—				(52,620	)			—				(52,620	)
Other, net			1,866				4,235				(2,369	)			(6,812	)			4,559				(11,371	)
Income tax (expense) benefit			(2,093	)			3,697				(5,790	)			(11,357	)			(5,773	)			(5,584	)
Income from discontinued operations			324				—				324				410				—				410
Net income		$	(4,826	)		$	34,267			$	(39,093	)		$	178,776			$	455,775			$	(276,999	)

 

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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 or their respective subsidiaries and the principal sources of cash flow are its direct and indirect investments in the limited 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,
		2010				2009				Change				2010				2009				Change
Equity in earnings of affiliates		$	102,388			$	82,661			$	19,727			$	324,128			$	370,195			$	(46,067	)
Selling, general and administrative			(2,920	)			(786	)			(2,134	)			(20,335	)			(3,608	)			(16,727	)
Interest expense, net of interest capitalized			(89,484	)			(18,589	)			(70,895	)			(126,400	)			(56,728	)			(69,672	)
Losses on non-hedged interest rate derivatives			(18,211	)			(17,348	)			(863	)			(53,388	)			(7,954	)			(45,434	)
Other, net			(6,736	)			957				(7,693	)			(6,949	)			329				(7,278	)

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in ETP and Regency. For the three and nine months ended September 30, 2010, the changes in equity in earnings of affiliates compared to the same period in the prior year are primarily due to corresponding changes in earnings from ETP. An analysis of ETP’s results is included in “Segment Operating Results” below. The three and nine months ended September 30, 2010 also reflect the equity in earnings from Regency subsequent to our acquisition of a controlling interest in Regency on May 26, 2010.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $2.1 million and $16.7 million for the three and nine months ended September 30, 2010 primarily due to expenses associated with the Regency Transactions.

Interest Expense. For the three and nine months ended September 30, 2010 compared to the same periods in the prior year, interest expense was primarily impacted by the recognition of $66.4 million of realized losses on hedged interest rate swaps that were terminated with the proceeds from our September 2010 senior notes offering. In addition to the $66.4 million of realized losses on hedged interest rate swaps, we also paid $102.2 million to terminate non-hedged interest rate swaps. The $102.2 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings. The total cash paid to terminate interest rate swaps was $168.6 million, including realized losses on hedged and non-hedged swaps.

Prior to termination of the swaps, the unrealized loss had been reflected in accumulated other comprehensive income. In addition to the realized loss from swap terminations, interest expense is also higher due to distributions on the Preferred Units issued in May 2010. For the three and nine months ended September 30, 2010, interest expense includes distributions on the ETE Preferred Units of $6.0 million and $8.4 million, respectively.

Losses on Non-Hedged Interest Rate Derivatives. The Parent Company terminated its interest rate swaps that were not accounted for as hedges in September 2010. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings. The variable portion of these swaps is based on the three month LIBOR and its corresponding forward curve. Increases in losses on non-hedged interest rate derivatives are due to changes in these rates. We recorded unrealized losses on our interest rate swaps as a result of decreases in the relevant floating index rates during the periods presented.

 

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Segment Operating Results

As a result of the Regency Transactions in May 2010, our reportable segments were reevaluated and now 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 and its General Partner, ETP GP.

 

•

Investment in Regency — Reflects the consolidated operations of Regency and its General Partner, Regency GP.

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 to our condensed consolidated financial statements.

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

Net income (loss) by segment is as follows:

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2010				2009				Change				2010				2009				Change
Investment in ETP		$	107,387			$	72,456			$	34,931			$	390,341			$	530,361			$	(140,020	)
Investment in Regency			7,846				—				7,846				2,951				—				2,951
Corporate and Other			(120,059	)			(38,189	)			(81,870	)			(214,516	)			(74,586	)			(139,930	)
Net income		$	(4,826	)		$	34,267			$	(39,093	)		$	178,776			$	455,775			$	(276,999	)

Investment in ETP

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2010				2009				Change				2010				2009				Change
Revenues		$	1,290,644			$	1,129,596			$	161,048			$	4,430,331			$	3,911,513			$	518,818
Cost of products sold			777,411				678,148				99,263				2,773,133				2,263,280				509,853
Gross margin			513,233				451,448				61,785				1,657,198				1,648,233				8,965
Operating expenses			174,740				158,883				15,857				515,021				517,337				(2,316	)
Depreciation and amortization			85,612				81,684				3,928				252,765				230,461				22,304
Selling, general and administrative			44,734				33,534				11,200				137,743				143,015				(5,272	)
Operating income			208,147				177,347				30,800				751,669				757,420				(5,751	)
Interest expense, net of interest capitalized			(101,241	)			(101,503	)			262				(309,217	)			(284,228	)			(24,989	)
Equity in earnings of affiliates			595				9,581				(8,986	)			10,848				11,751				(903	)
Gains (losses) on disposal of assets			281				(1,088	)			1,369				(198	)			(1,333	)			1,135
Gains (losses) on non-hedged interest rate derivatives			(11,963	)			(18,241	)			6,278				(11,963	)			32,327				(44,290	)
Allowance for equity funds used during construction			12,432				30				12,402				18,039				18,618				(579	)
Impairment of investment in affiliate			—				—				—				(52,620	)			—				(52,620	)
Other, net			1,129				3,433				(2,304	)			(3,731	)			4,400				(8,131	)
Income tax (expense) benefit			(1,993	)			2,897				(4,890	)			(12,486	)			(8,594	)			(3,892	)
Net income		$	107,387			$	72,456			$	34,931			$	390,341			$	530,361			$	(140,020	)

 

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Gross Margin. For the three months ended September 30, 2010 compared to the three months ended September 30, 2009, ETP’s gross margin increased primarily due to:

 

•

an increase in transportation fees on ETP’s intrastate transportation system due to the impact of a more favorable natural gas price environment and basis differentials between the West and East Texas market hubs; and

 

•

an increase in margins from storage-related activities.

For the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009, the favorable impacts experienced in ETP’s intrastate transportation and storage business (as discussed above) were offset by the impacts of lower volumes on ETP’s intrastate transportation system during the first six months of 2010 as a result of a less favorable natural gas price environment and basis differential.

Operating Expenses. For the three months ended September 30, 2010, operating expenses increased approximately $15.9 million primarily due to increased maintenance and ad valorem expenses related to ETP’s midstream and intrastate transportation and storage businesses.

Depreciation and Amortization. Depreciation and amortization expense increased primarily due to incremental depreciation related to our continued expansion of our pipeline and midstream systems.

Selling, General and Administrative. For the three months ended September 30, 2010, selling, general and administrative expenses increased approximately $11.2 million primarily due to increases in employee-related costs.

For the nine months ended September 30, 2010, selling, general and administrative expenses decreased approximately $5.3 million primarily due to a decrease in professional fees incurred.

Interest Expense. Interest expense increased $25.0 million for the nine months ended September 30, 2010 compared to the same period in the previous year principally due to ETP’s issuance of $1.0 billion in senior notes in April 2009 and ETP’s subsidiary’s issuance of $350.0 million of senior notes in December 2009.

Equity in Earnings of Affiliates. Equity in earnings of affiliates decreased $9.0 million for the three months ended September 30, 2010 compared to the same period in the previous year primarily due to our transfer of substantially all of ETP’s interest in MEP to the Parent Company on May 26, 2010. For the nine months ended September 30, 2010, the impact of the MEP transfer is offset by increased earnings from MEP during the period prior to May 26, 2010 as a result of placing the Midcontinent Express pipeline into service in 2009.

Gains (Losses) on Non-Hedged Interest Rate Derivatives. For the three months ended September 30, 2010 and 2009, the losses on non-hedged interest rate derivatives reflect declines in the index rate used during the periods. In addition, the losses on non-hedged interest rate derivatives were lower for the three months ended September 30, 2010 compared to the same period in the prior year due to a decrease in the notional amount of interest rate swaps outstanding during the period. As of September 30, 2010 and 2009, ETP had $400.0 million and $500.0 million, respectively, of total notional amount of interest rate swaps outstanding that were not designated as hedges for accounting purposes.

ETP did not have any non-hedged interest rate swaps outstanding during the first six months of 2010; therefore, the losses on non-hedged interest rate derivatives for the nine months ended September 30, 2010 reflect the losses recognized during the last three months of that period. For the nine months ended September 30, 2009, the gains on non-hedged interest rate swaps resulted from an increase in the index rate during the period.

Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction (AFUDC) increased $12.4 million for the three months ended September 30, 2010, primarily due to construction on the Tiger pipeline.

Impairment of Investment in Affiliate. In conjunction with the transfer of its interest in MEP, 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 its estimated fair value.

 

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Investment in Regency

 

		Three Months Ended September  30,												Nine Months Ended September  30,
		2010				2009				Change				2010				2009				Change
Revenues		$	296,888			$	—			$	296,888			$	393,868			$	—			$	393,868
Cost of products sold			213,032				—				213,032				283,206				—				283,206
Gross margin			83,856				—				83,856				110,662				—				110,662
Operating expenses			34,306				—				34,306				44,708				—				44,708
Depreciation and amortization			32,205				—				32,205				42,750				—				42,750
Selling, general and administrative			18,072				—				18,072				25,176				—				25,176
Losses on disposal of assets			200				—				200				210				—				210
Operating loss			(927	)			—				(927	)			(2,182	)			—				(2,182	)
Interest expense, net of interest capitalized			(20,379	)			—				(20,379	)			(28,460	)			—				(28,460	)
Equity in earnings of affiliates			21,754				—				21,754				29,875				—				29,875
Other, net			7,524				—				7,524				4,003				—				4,003
Income tax expense			(450	)			—				(450	)			(695	)			—				(695	)
Income from discontinued operations			324				—				324				410				—				410
Net income		$	7,846			$	—			$	7,846			$	2,951			$	—			$	2,951

Amounts reflected above for the three and nine months ended September 30, 2010 represent the results of operations for Regency from May 26, 2010, the date ETE obtained control of Regency, through September 30, 2010. Changes between periods are due to the consolidation of Regency beginning May 26, 2010.

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

In addition, Regency’s results included its equity in earnings related to its 49.9% interest in MEP from May 26, 2010 through September 30, 2010.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The Parent Company currently has no separate operating activities apart from those conducted by ETP, Regency or their respective subsidiaries. Following the completion of the Regency Transactions on May 26, 2010, our equity interests in ETP consist of approximately 50.2 million common units, an approximate 1.8% general partner interest and 100% of the incentive distribution rights, and our equity interests in Regency consist of approximately 26.3 million common units, a 2.0% general partner interest and 100% of the incentive distribution rights. The principal sources of our cash flow are cash distributions resulting from our direct and indirect investments in the limited and general partner interests of ETP and Regency. The amount of cash that ETP and Regency distributes 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, generated with respect to such quarter.

In September 2010, the Parent Company completed a public offering of $1.8 billion aggregate principal amount of 7.5% Senior Notes due October 15, 2020. We used net proceeds of approximately $1.77 billion to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate the interest rate swap agreements related to those borrowings, and for general partnership purposes. We may redeem some or all of the notes at any time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.

Concurrent with this debt offering, the Parent Company entered into a $200.0 million revolving credit facility that expires in September 2015 and has available capacity of $200.0 million as of September 30, 2010.

 

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The Parent Company’s primary cash requirements are for general and administrative expenses and debt service requirements and distributions to the holders of our Preferred Units. The Parent Company currently expects to fund its short-term needs for such items with the cash distributions it receives each quarter from ETP and Regency. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

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

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 management’s control.

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

 

•

growth capital expenditures for its midstream and intrastate transportation and storage segments, primarily for the construction of new pipelines and compression, for which ETP expects to spend between $75 million and $125 million during the last three months of 2010 and between $100 million and $200 million in 2011;

 

•

growth capital expenditures for its interstate transportation segment, excluding capital contributions to its joint ventures as discussed below, for the construction of new pipelines for which ETP expects to spend between $200 million and $270 million during the last three months of 2010 and between $180 million and $225 million in 2011;

 

•

growth capital expenditures for its retail propane segment of between $10 million and $20 million during the last three months of 2010 and between $25 million and $35 million in 2011; and

 

•

maintenance capital expenditures of between $25 million and $40 million during the last three months of 2010 and between $120 million and $140 million in 2011, which include (i) capital expenditures for its intrastate operations for pipeline integrity and for connecting additional wells to its intrastate natural gas systems in order to maintain or increase throughput on existing assets; (ii) capital expenditures for its interstate operations, primarily for pipeline integrity; and (iii) capital expenditures for its propane operations to extend the useful lives of its existing propane assets in order to sustain its operations, including vehicle replacements on its propane vehicle fleet.

ETP may enter into acquisitions, including the potential acquisition of new pipeline systems and propane operations.

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

ETP raised approximately $423.6 million in net proceeds from its common unit offering in January 2010 and $489.4 million in net proceeds from its common unit offering in August 2010. In addition, ETP raised $174.1 million in net proceeds during the nine months ended September 30, 2010 under ETP’s Equity Distribution Agreement, as described in Note 12 to our condensed consolidated financial statements. As of September 30, 2010, in addition to approximately $77.7 million of cash on hand, ETP had available capacity under the ETP revolving credit facility (“ETP Credit Facility”) of approximately $1.98 billion. Based on our current estimates, we expect to utilize these resources, along with cash from ETP’s operations, to fund our announced growth capital expenditures and working capital needs through the end of 2011; however, the Parent Company or ETP may issue debt or equity securities prior to that time as we deem prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.

 

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Regency Energy Partners

Regency expects its sources of liquidity to include:

 

•

cash generated from operations;

 

•

borrowings under its revolving credit facility, which we refer to as the Regency Credit Facility;

 

•

operating lease facilities;

 

•

asset sales;

 

•

debt offerings; and

 

•

issuance of additional partnership units.

Regency raised approximately $400.2 million in net proceeds from its common unit offering in August 2010. As of September 30, 2010, in addition to approximately $4.0 million of cash on hand, Regency had available capacity under its revolving credit facility of approximately $509.0 million.

Regency expects its growth capital expenditures to be approximately $116 million during the last three months of 2010, exclusive of its proportionate share of the growth capital expenditures related to HPC or MEP. Regency has not publicly announced its expected capital expenditures for 2011.

Although Regency intends to move forward with its planned internal growth projects, it may further revise the timing and scope of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to its Unitholders from its expansion activities may be reduced by substantial cost of capital increases during this period.

In addition, Regency expects capital contributions to joint ventures during the last three months of 2010 to be $46.9 million.

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 purchase and sales of propane and natural gas inventories, and the timing of advances and deposits received from customers.

Nine months ended September 30, 2010 compared to nine months ended September 30, 2009. Cash provided by operating activities during 2010 was $927.7 million as compared to $721.4 million for 2009. Net income was $178.8 million and $455.8 million for 2010 and 2009, respectively. The difference between net income and the net cash provided by operating activities consisted of non-cash items totaling $389.1 million and $261.1 million and changes in operating assets and liabilities of $430.8 million and $10.2 million for 2010 and 2009, respectively. For the three and nine months ended September 30, 2010, the difference between net income and the net cash provided by operating activities also included ETP interest rate swap termination proceeds of $26.5 million, ETE payments to terminate interest rate swaps of $168.6 million and distributions received from our affiliates that exceeded our equity in earnings by $71.0 million.

 

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The non-cash activity in 2010 and 2009 consisted primarily of depreciation and amortization of $304.7 million and $239.6 million, respectively, and an impairment in our investment of an affiliate of $52.6 million recorded in 2010. In addition, non-cash compensation expense was $23.5 million and $22.3 million for 2010 and 2009, respectively. These amounts are partially offset by the allowance for equity funds used during construction of $18.0 million and $18.6 million for 2010 and 2009, respectively.

Cash paid for interest, net of interest capitalized, was $429.7 million and $341.6 million for the nine months ended September 30, 2010 and 2009, 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. Growth capital expenditures for ETP for 2010 are primarily related to the Tiger pipeline in its Interstate transportation segment, which is expected to be placed in service in December 2010.

Nine months ended September 30, 2010 compared to nine months ended September 30, 2009. Cash used in investing activities during 2010 was $1.40 billion as compared to $1.23 billion for 2009. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2010 were $1.13 billion, including changes in accruals of $21.2 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2009 of $703.5 million, including changes in accruals of $98.3 million. In addition, in 2010 Regency paid cash for acquisitions of $191.3 million, ETP paid cash for acquisitions of $156.4 million, and we received $24.0 million in cash in the acquisition of Regency. Regency received $70.2 million in cash for the sale of its East Texas assets. Our subsidiaries made advances to joint ventures of $45.0 million. In 2009, ETP made advances to its joint ventures of $534.5 million.

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, as discussed below, which are primarily used to fund acquisitions and growth capital expenditures. Distributions to partners increase between the periods based on increases in the number of common units outstanding, as discussed below under “Cash Distributions.”

Nine months ended September 30, 2010 compared to nine months ended September 30, 2009. Cash provided by financing activities during 2010 was $489.8 million as compared to $462.5 million for 2009. In 2010, ETP received $1.09 billion in net proceeds from offerings of common units, including $174.1 million under ETP’s Equity Distribution Agreement, as compared to $578.9 million in 2009 (see Note 12 to our condensed consolidated financial statements). In addition, Regency received $400.2 million in net proceeds from offerings of common units in 2010. During 2010, we had a consolidated net decrease in our debt level of $206.6 million as compared to a net increase of $520.6 million for 2009. We paid distributions of $362.3 million to our partners in 2010 as compared to $351.0 million in 2009. In addition, during 2010 and 2009, ETP paid distributions of $348.3 million and $278.3 million, respectively, of distributions on limited partner interests other than those held by the Parent Company and Regency paid $42.5 million in 2010. These distributions are reflected as distributions to noncontrolling interests on our condensed consolidated statements of cash flows.

 

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:

 

		September 30, 2010				December 31, 2009
Parent Company Indebtedness:
ETE Senior Notes		$	1,800,000			$	—
Senior secured revolving credit facilities			—				123,951
Senior Secured Term Loan Facility			—				1,450,000
Subsidiary Indebtedness:
ETP Senior Notes			5,050,000				5,050,000
Regency Senior Notes			607,500				—
Transwestern Senior Unsecured Notes			870,000				870,000
HOLP Senior Secured Notes			105,127				140,512
ETP Revolving Credit Facility			—				150,000
Regency Revolving Credit Facility			375,000				—
HOLP Revolving Credit Facility			—				10,000
Other long-term debt			8,434				10,288
Unamortized premiums (discounts)			554				(12,829	)
Fair value adjustments related to interest rate swaps			18,663				—
Total debt		$	8,835,278			$	7,791,922

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, 2009, filed with the SEC on February 24, 2010.

Parent Company Indebtedness

In September 2010, the Parent Company completed a public offering of $1.8 billion aggregate principal amount of 7.5% Senior Notes due October 15, 2020. We used net proceeds of approximately $1.77 billion to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate the interest rate swap agreements related to those borrowings, and for general partnership purposes. We may redeem some or all of the notes at any time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.

Concurrent with the closing of its senior notes offering in September 2010, the Parent Company terminated its $500 million senior secured revolving credit facility and entered into a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. As of September 30, 2010, there were no outstanding borrowings under the Parent Company Credit Agreement.

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

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

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

 

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Subsidiary Indebtedness

In addition to the ETP Senior Notes disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009, our subsidiaries have the following notes outstanding.

Regency Senior Notes

Senior Notes due 2018. Subsequent to September 30, 2010, Regency completed a public offering of $600.0 million aggregate principal amount of its 6.875% Senior Notes due 2018. The sale of the notes closed on October 27, 2010 and Regency will use the net proceeds to fund a tender offer and to reduce outstanding borrowings under its revolving credit facility.

Regency Senior Notes due 2016. Regency has $250.0 million of senior notes that mature on June 1, 2016. The senior notes bear interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1.

At any time before June 1, 2012, up to 35% of the senior notes can be redeemed at a price of 109.375% plus accrued interest. Beginning June 1, 2013, Regency may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, Regency may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined in the indenture governing the senior notes) as of such redemption date plus 0.50% over the principal amount of the note.

Senior Notes due 2013. Regency has $357.5 million senior notes that mature on December 15, 2013. The senior notes bear interest at 8.375% and interest is payable semi-annually in arrears on each June 15 and December 15.

On October 13, 2010, Regency announced that it commenced a cash tender offer and consent solicitation for its outstanding 8.375% senior notes due 2013 (the “Tender Offer”). On October 27, 2010, Regency accepted for purchase approximately $271.1 million of its senior notes due 2013 pursuant to the Tender Offer. The Tender Offer will expire 8:00 a.m., New York City time, on November 10, 2010. Regency currently anticipates that it will call for redemption any senior notes due 2013 not purchased in the Tender Offer and will satisfy and discharge the indenture relating to the senior notes due 2013 in compliance with the terms of the notes, the indenture and applicable law; provided, however, that it may elect not to redeem such notes or satisfy and discharge the related indenture.

Revolving Credit Facilities

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

As of September 30, 2010, there were no outstanding borrowings under the ETP Credit Facility. Taking into account letters of credit of approximately $22.4 million, the amount available for future borrowings was $1.98 billion.

Regency Credit Facility. Regency maintains the Regency Credit Facility through its subsidiary, Regency Gas Services LP (“RGS”). The Regency Credit Facility has aggregate revolving commitments of $900 million, with $200 million of availability for letters of credit. RGS 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; however, the maturity date will be accelerated to June 15, 2013 if Regency’s senior notes due 2013 have not been redeemed or refinanced by that date.

 

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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% and an adjusted one-month LIBOR rate plus 1.50%. 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 0.500% based upon the consolidated leverage ratio of Regency. RGS must also pay a participation fee for each revolving lender participating in letters of credit based upon the applicable margin, which is currently 2.9% of the average daily amount of such lender’s letter of credit exposure, and a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of the letter of credit exposure.

As of September 30, 2010, there was a balance outstanding in the Regency Credit Facility of $375.0 million in revolving credit loans and approximately $16.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2010, which is reduced by any letters of credit, was approximately $509.0 million. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 3.2%.

HOLP Credit Facility. HOLP has a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available through June 30, 2011, which may be expanded to $150.0 million. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the credit agreement for the HOLP Credit Facility, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secure the HOLP Credit Facility. At September 30, 2010, there was no outstanding balance in revolving credit loans and outstanding letters of credit of $0.5 million. The amount available for borrowing as of September 30, 2010 was $74.5 million.

Other

MEP Guarantee

ETP has guaranteed 50% of the obligations of MEP under its senior revolving credit facility (the “MEP Facility”), with the remaining 50% of MEP Facility obligations guaranteed by KMP. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions. Although ETP transferred substantially all of its interest in MEP on May 26, 2010, ETP will continue to guarantee 50% of MEP’s obligations under this facility through the maturity of the facility in February 2011. Regency has agreed to indemnify ETP for any costs related to the guaranty of payments under this facility.

Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if our ownership percentage in MEP increases or decreases. The MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

As of September 30, 2010, MEP had $82.2 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. Our contingent obligations with respect to our 50% guarantee of MEP’s outstanding borrowings and letters of credit were $41.1 million and $16.6 million, respectively, as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 0.9%.

FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP has guaranteed 50% of the obligations of FEP under the FEP Facility, with the remaining 50% of FEP Facility obligations guaranteed by KMP. Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012. Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the FEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 1.0%.

 

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As of September 30, 2010, FEP had $847.0 million of outstanding borrowings issued under the FEP Facility. ETP’s contingent obligation with respect to our 50% guarantee of FEP’s outstanding borrowings was $423.5 million as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 3.3%.

Covenants Related to Our Credit Agreements

We, ETP and Regency were in compliance with all requirements, tests, limitations, and covenants related to our respective debt agreements at September 30, 2010.

CONTRACTUAL OBLIGATIONS

The following table summarizes our long-term debt and other contractual obligations as of September 30, 2010. These amounts increased due to the Regency Transactions:

 

		Payments Due by Period
Contractual Obligations		Total				Remainder of 2010				2011-2012				2013-2014				Thereafter
Long-term debt		$	8,816,061			$	3,094			$	457,702			$	1,548,821			$	6,806,444
Interest on long-term debt (a)			6,043,854				115,872				1,257,095				1,125,775				3,545,112
Payments on derivatives			12,988				25				12,963				—				—
Purchase commitments (b)			986,473				301,081				433,578				223,835				27,979
Lease obligations			335,045				14,999				52,422				43,086				224,538
Distributions and Redemption of Preferred Units (c)			325,398				7,945				63,563				55,223				198,667
Totals		$	16,519,819			$	443,016			$	2,277,323			$	2,996,740			$	10,802,740

 

(a)

Interest payments on long-term debt are based on the principal amount of debt obligations at September 30, 2010. With respect to variable rate debt, the interest payments were estimated using the interest rate as of September 30, 2010. To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.

 

(b)

We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for propane and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the September 30, 2010 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated.

 

(c)	Assumes the Regency Preferred Units are redeemed for cash on September 2, 2029.

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.

 

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Distributions paid by the Parent Company are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per Common Unit
December 31, 2009		February 8, 2010		February 19, 2010		$	0.54
March 31, 2010		May 7, 2010		May 17, 2010			0.54
June 30, 2010		August 9, 2010		August 19, 2010			0.54

On October 28, 2010, the Parent Company announced the declaration of a cash distribution for the three months ended September 30, 2010 of $0.54 per Common Unit, or $2.16 annualized. This distribution will be paid on November 19, 2010 to Unitholders of record at the close of business on November 8, 2010.

The total amounts of distributions declared during the nine months ended September 30, 2010 and 2009 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,
		2010				2009
Limited Partners		$	361,164			$	355,523
General Partner			1,122				1,104
Total distributions declared		$	362,286			$	356,627

Cash Distributions Received from Subsidiaries

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

 

		Nine Months Ended September 30,
		2010				2009
Distributions received from ETP (1):
Limited Partners (2)		$	145,640			$	167,580
General Partner Interest			14,634				14,626
Incentive Distribution Rights			279,823				256,530
Total distributions received from ETP (3)			440,097				438,736
Distributions received from Regency (4):
Limited Partners			23,378				—
General Partner Interest			2,372				—
Incentive Distribution Rights			1,965				—
Total distributions received from Regency (5)			27,715				—
Total distributions received		$	467,812			$	438,736

 

(1)	Includes distributions declared by ETP for the three months ended September 30, 2010 that will be paid on November 15, 2010 to holders of record on November 8, 2010.

 

(2)	As of September 30, 2010, we held 50,226,967 ETP Common Units. This amount reflects the redemption of 12.3 million ETP Common Units in connection with the Regency Transactions.

 

(3)	The distributions paid for the prior periods do not reflect the reduction in the number of ETP Common Units held by us as a result of the Regency Transactions and the associated expected reduction in distributions payable in respect of the incentive distribution rights.

 

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On a pro forma basis assuming no change from ETP’s historical quarterly distribution rates, after giving effect to the reduction in ETP Common Units held by us as a result of the Regency Transactions and the associated reduction in distributions payable in respect of the incentive distribution rights as if the Regency Transactions had been completed on January 1, 2010, we would have received $423.2 million in distributions from ETP for the nine months ended September 30, 2010, of which $14.6 million would have related to our general partner interest, $273.9 million to our incentive distribution rights and $134.7 million to the approximately 50.2 million ETP Common Units we currently own.

 

(4)	Includes distributions declared by Regency for the three months ended September 30, 2010 that will be paid on November 12, 2010 to holders of record on November 5, 2010.

 

(5)	Our equity interests in Regency consist of approximately 26.3 million common units, a 2.0% general partner interest and 100% of the incentive distribution rights.

On a pro forma basis assuming no change from Regency’s historical quarterly distribution rates, after giving effect to the acquisition of our equity interests in Regency pursuant to the Regency Transactions, we would have received $42.0 million in distributions from Regency for the nine months ended September 30, 2010, of which $3.8 million would have related to our general partner interest, $3.2 million to our incentive distribution rights and $35.0 million to the approximately 26.3 million Regency Common Units we currently own.

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 its general partner.

Cash Distributions Paid by ETP

Distributions paid by ETP are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per Common Unit
December 31, 2009		February 8, 2010		February 15, 2010		$	0.89375
March 31, 2010		May 7, 2010		May 17, 2010			0.89375
June 30, 2010		August 9, 2010		August 16, 2010			0.89375

On October 28, 2010, ETP declared a cash distribution for the three months ended September 30, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on November 15, 2010 to Unitholders of record at the close of business on November 8, 2010.

The total amounts of ETP distributions declared during the nine months ended September 30, 2010 and 2009 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,
		2010				2009
Limited Partners:
Common Units		$	503,582			$	460,132
Class E Units			9,363				9,363
General Partner Interest			14,634				14,626
Incentive Distribution Rights			279,823				256,530
Total distributions declared by ETP		$	807,402			$	740,651

 

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Cash Distributions Paid by Regency

Distributions paid by Regency are summarized as follows:

 

Quarter Ended		Record Date		Payment Date		Distribution per Common Unit
June 30, 2010		August 6, 2010		August 13, 2010		$	0.445

On October 26, 2010, Regency declared a cash distribution for the three months ended September 30, 2010 of $0.445 per Common Unit, or $1.78 annualized. This distribution will be paid on November 12, 2010 to Unitholders of record at the close of business on November 5, 2010.

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

 

		Nine Months Ended September 30,
		2010				2009
Limited Partners		$	114,270			$	—
General Partner Interest			2,372				—
Incentive Distribution Rights			1,965				—
Total distributions declared by Regency		$	118,607			$	—

NEW ACCOUNTING STANDARDS AND CRITICAL ACCOUNTING POLICIES

Disclosure of our critical accounting policies and the impacts of new accounting standards is included in our Annual Report on Form 10-K for the year ended December 31, 2009. As a result of the Regency Transactions on May 26, 2010, the following critical accounting policies changed as compared to the critical accounting policies described in our Form 10-K for the year ended December 31, 2009.

Revenue Recognition

In addition to the policy in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, Regency provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput and cash flow. Regency is responsible for the installation and ongoing operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. Revenues for compression services are recognized when the service is performed.

FORWARD-LOOKING STATEMENTS

This quarterly report contains forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations 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, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations, cash flow and financial condition and our ability to make schedule payments on or to refinance our debt obligations are:

 

•

the ability of our subsidiaries, ETP and Regency, to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP and Regency;

 

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•

the actual amount of cash distributions by ETP and Regency to us, which is affected by the amount, if any, of cash reserves established by the respective Board of Directors of the General Partner of ETP and Regency and is outside of our control;

 

•

the amount of natural gas transported on ETP’s and Regency’s pipelines and gathering systems;

 

•

the level of throughput in ETP’s and Regency’s natural gas processing and treating facilities;

 

•

the fees charged and the margins realized by ETP and Regency for gathering, treating, processing, storage and transportation services;

 

•

the prices and market demand for, and the relationship between, natural gas and natural gas liquids, or NGLs;

 

•

energy prices generally;

 

•

the prices of natural gas and propane compared to the price of alternative and competing fuels;

 

•

the general level of petroleum product demand and the availability and price of propane supplies;

 

•

the level of domestic oil, propane and natural gas production;

 

•

the availability of imported oil and natural gas;

 

•

ETP’s ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;

 

•

actions taken by foreign oil and gas producing nations;

 

•

the political and economic stability of petroleum producing nations;

 

•

the effect of weather conditions on demand for oil, natural gas and propane;

 

•

availability of local, intrastate and interstate transportation systems;

 

•

ETP’s and Regency’s continued ability to find and contract for new sources of natural gas supply;

 

•

availability and marketing of competitive fuels;

 

•

the impact of energy conservation efforts;

 

•

energy efficiencies and technological trends;

 

•

governmental regulation and taxation;

 

•

changes to, the application of, and the regulation of tariff rates and operational requirements related to ETP’s and Regency’s pipelines;

 

•

hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance;

 

•

the maturity of the propane industry and competition from other propane distributors;

 

•

competition from other midstream companies, interstate pipeline companies and propane distribution companies;

 

•

loss of key personnel;

 

•

loss of key natural gas producers or the providers of fractionation services;

 

•

reductions in the capacity or allocations of third party pipelines that connect with ETP’s and Regency’s pipelines and facilities;

 

•

the effectiveness of risk-management policies and procedures and the ability of ETP’s and Regency’s liquids marketing counterparties to satisfy their financial commitments;

 

•

the nonpayment or nonperformance by ETP’s and Regency’s customers;

 

•

regulatory, environmental, political and legal uncertainties that may affect the timing and cost of ETP’s or Regency’s internal growth projects;

 

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•

risks associated with the construction of new pipelines and treating and processing facilities or additions to ETP’s or Regency’s existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third party contractors;

 

•

the availability and cost of capital and ETP’s and Regency’s ability to access certain capital sources;

 

•

the further deterioration of the credit and capital markets;

 

•

the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to ETP’s or Regency’s financial results and to successfully integrate acquired businesses;

 

•

changes in laws and regulations to which we, ETP and Regency are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and

 

•

the costs and effects of legal and administrative proceedings.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Risk Factors” in Item 1A of this report.

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, 2009, in addition to the interim unaudited condensed consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2009, other than additional primary market risk exposures related to the Regency Transactions. We have begun to periodically enter into interest rate swaptions when our targeted benchmark interest rates for anticipated debt issuances are not attainable at the time in the interest rate swap market. Swaptions enable counterparties to exercise options to enter into interest rate swaps with us in exchange for premiums. Our swaption activity is further discussed in Note 16 to our condensed consolidated financial statements. Other than changes due to the Regency Transactions and our swaptions activities, there have been no material changes to our primary market risk exposures or how those exposures are managed since December 31, 2009

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 (“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 its existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

 

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Commodity Price Risk

The table below summarizes our commodity-related financial derivative instruments and fair values as of September 30, 2010 and December 31, 2009, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. 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, 2010												December 31, 2009
		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			(33,870,000	)		$	(205	)		$	1,621				72,325,000			$	24,554			$	491
Swing Swaps IFERC			11,735,000				(938	)			151				(38,935,000	)			1,718				2,142
Fixed Swaps/Futures			486,000				3,962				275				4,852,500				9,949				3,126
Options — Puts			440,000				13,976				1,748				2,640,000				837				447
Options — Calls			(3,440,000	)			(8,567	)			179				(2,640,000	)			(819	)			314
Propane:
Forwards/Swaps			—				—				—				6,090,000				3,348				785
Natural Gas Liquids:
Forwards/Swaps			348,000				2,574				3,230				—				—				—
WTI Crude Oil:
Forwards/Swaps			59,800				2,385				481				—				—				—
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX			(10,060,000	)			(307	)			118				(22,625,000	)			(4,178	)			2
Fixed Swaps/Futures			(20,160,000	)			17,739				8,504				(27,300,000	)			(13,285	)			15,669
Cash Flow Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX			(4,445,000	)			(640	)			25				(13,225,000	)			(1,640	)			81
Fixed Swaps/Futures			(5,440,000	)			19,954				3,682				(22,800,000	)			(4,464	)			13,197
Options — Puts			22,680,000				15,049				5,628				—				—				—
Options — Calls			(22,680,000	)			6,991				856				—				—				—
Propane:
Forwards/Swaps			58,086,000				5,685				6,901				20,538,000				8,443				2,609
Natural Gas Liquids:
Forwards/Swaps			1,359,340				(2,924	)			5,405				—				—				—
WTI Crude:
Forwards/Swaps			249,295				(757	)			2,108				—				—				—

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

 

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Interest Rate Risk

As of September 30, 2010, Regency had $375.0 million of variable rate debt outstanding on its revolving credit facilities. We and ETP had no variable rate debt outstanding as of September 30, 2010. We also had the following interest rate swaps outstanding as of September 30, 2010 (dollars in thousands):

 

Entity		Term		Notional Amount				Type		Hedge Designation
ETP		August 2012		$	400,000			Forward starting to pay a fixed rate of 3.64% and receive a floating rate		Undesignated
Regency		April 2012			250,000			Pay a fixed rate of 1.325% and receive a floating rate		Undesignated

A hypothetical change of 1.0% in interest rates related to net floating rate debt would result in a change to consolidated interest expense of approximately $3.8 million annually. Additionally, a hypothetical change of 1.0% in interest rates for interest rate swaps not designated as hedges would result in a net change in the fair value of interest rate derivatives and earnings of approximately $34.9 million.

Credit Risk

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

Our counterparties consist primarily of financial institutions, major energy companies and local distribution 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. Based on our policies, exposures, credit and other reserves, 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 condensed consolidated balance sheet and recognized in net income or other comprehensive income.

Regency is exposed to credit risk from its derivative counterparties. Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

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, 2010 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.

 

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Changes in Internal Control over Financial Reporting

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We closed the Regency Transactions on May 26, 2010 and have begun the evaluation of the internal control structure of Regency. We expect that evaluation to continue during the remainder of 2010. In recording the Regency acquisition, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of Regency that are included in our earnings for the three months ended September 30, 2010.

 

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2009 and Note 15 — Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Condensed Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2010.

ITEM 1A. RISK FACTORS

For information regarding risks, uncertainties and assumptions, see Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009. Except as disclosed below, there are no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010.

Tax Risks to Common Unitholders

The sale or exchange of 50% or more of our capital and profit interests during any twelve month period will result in the termination of our partnership for federal income tax purposes.

We will be considered terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all Unitholders which would require us to file two tax returns for one fiscal year, and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a Unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such Unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes. We would be treated as a new partnership for tax purposes, and would be required to make new tax elections and could be subject to penalties if we were unable to determine in a timely manner that a termination occurred.

In September 2010, Enterprise GP Holdings L.P., which holds approximately 17.6% of the outstanding common units of ETE and an approximate 40.6% interest in ETE’s general partner, announced an agreement to merge into Enterprise Products Partners L.P. For federal income tax purposes, this transaction will be treated as a change of ownership of the interests in ETE and its general partner owned by Enterprise GP Holdings L.P. As a result, if and when this transaction is consummated, it will increase the likelihood that a termination of our partnership for federal income tax purposes may occur at that time or at any time during the twelve-month period following the consummation of the transaction resulting in a closing of our taxable year, as discussed above.

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/A) (5/13/10)		2.1		General Partner Purchase Agreement, dated May 10, 2010, by and among Regency GP Acquirer, L.P., Energy Transfer Equity, L.P. and ETE GP Acquirer LLC.
2.2		1-32740 (8-K/A) (5/13/10)		2.2		Redemption and Exchange Agreement, dated May 10, 2010, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P.
2.3		1-32740 (8-K/A) (5/13/10)		2.3		Contribution Agreement, dated May 10, 2010, by and among Energy Transfer Equity, L.P., Regency Energy Partners LP and Regency Midcontinent Express LLC.
3.1		333-128097 (S-1) (9/2/05)		3.1		Certificate of Conversion of Energy Transfer Company, L.P.
3.2		333-12809 (S-1) (9/2/05)7		3.2		Certificate of Limited Partnership of Energy Transfer Equity, L.P.
3.3		1-32740 (8-K) (2/14/06)		3.1		Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.
3.3.1		1-32740 (10-K) (8/31/06)		3.3.1		Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.
3.3.2		1-32740 (8-K) (11/13/07)		3.3.2		Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.
3.3.3		1-32740 (8-K) (6/2/10)		3.1		Amendment No. 3 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., effective as of May 26, 2010.
3.4		333-128097 (S-1) (9/2/05)		3.4		Certificate of Conversion of LE GP, LLC.
3.5		333-128097 (S-1) (9/2/05)		3.5		Certificate of Formation of LE GP, LLC.
3.6		1-32740 (8-K) (5/8/07)		3.6.1		Amended and Restated Limited Liability Company Agreement of LE GP, LLC.
3.6.1		1-32740 (8-K) (12/23/09)		3.1		Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of LE GP, LLC.
3.7		1-11727 (8-K) (7/29/09)		3.1		Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)
3.8		333-04018 (S-1/A) (6/21/96)		3.2		Agreement of Limited Partnership of Heritage Operating, L.P.
3.8.1		1-11727 (10-K) (8/31/00)		3.2.1		Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
3.8.2		1-11727 (10-Q) (5/31/02)		3.2.2		Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
3.8.3		1-11727 (10-Q) (2/29/04)		3.2.3		Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

 

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		Previously Filed *
Exhibit Number		With File Number (Form) (Period Ending or Date		As Exhibit
3.9		1-11727 (10-Q) (2/29/04)		3.3		Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.
3.10		1-11727 (10-Q) (2/28/02)		3.4		Amended Certificate of Limited Partnership of Heritage Operating, L.P.
3.11		1-11727 (10-Q) (5/31/07)		3.5		Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P.
3.12		1-11727 (10-Q) (5/31/07)		3.6		Third Amended and Restated Limited Liability Agreement of Energy Transfer Partners, L.L.C.
3.12.1		1-32740 (8-K) (8/10/10)		3.1		Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C.
3.13		333-128097 (S-1/A) (12/20/05)		3.13		Certificate of Formation of Energy Transfer Partners, L.L.C.
3.13.1		333-128097 (S-1/A) (12/20/05)		3.13.1		Certificate of Amendment of U.S. Propane, L.L.C.
3.14		333-128097 (S-1/A) (12/20/05)		3.14		Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P.
3.15		1-32740 (8-K) (8/10/10)		3.2		Second Amendment to Amended and Restated Limited Liability Company Agreement of Regency GP, L.L.C
4.1		1-32740 (8-K) (6/2/10)		4.1		Registration Rights Agreement by and among Energy Transfer Equity, L.P. and Regency GP Acquirer, L.P., dated as of May 26, 2010.
4.2		1-32740 (8-K) (9/20/10)		4.1		Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee.
4.3		1-32740 (8-K) (9/20/10)		4.2		First Supplemental Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes).
10.1		1-32740 (8-K) (9/20/10)		10.1		Credit Agreement dated as of September 20, 2010 among Energy Transfer Equity, L.P., Credit Suisse AG, as administrative agent and collateral agent, the other lenders party thereto and Credit Suisse Securities (USA) LLC, as sole lead arranger and sole bookrunner.
10.2		1-32740 (8-K) (9/20/10)		10.2		Pledge and Security Agreement dated September 20, 2010 among Energy Transfer Equity, L.P., the other grantors named therein and Credit Suisse AG, Cayman Islands Branch, as collateral agent.
31.1						Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1						Certification of President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101						Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009; (ii) our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009; (iii) our Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2010 and 2009; (iv) our Condensed Consolidated Statement of Equity for the nine months ended September 30, 2010; (v) our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009; and (vi) the notes to our Condensed Consolidated Financial Statements, tagged as blocks of text.

 

*	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 9, 2010		By:		/s/ John W. McReynolds
				John W. McReynolds
				President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)

 

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Exhibit 31.1

CERTIFICATION OF PRESIDENT (PRINCIPAL EXECUTIVE OFFICER)

AND CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. McReynolds, certify that:

 

1.

I have reviewed this quarterly report on Form 10-Q of Energy Transfer Equity, L.P.;

 

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.

I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

a.

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

 

b.

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c.

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d.

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.

I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a.

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and

 

b.

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 9, 2010

 

 

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Equity, L.P. (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2010, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John W. McReynolds, President and Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

 

(1)

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

 

(2)

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

Date: November 9, 2010

 

*A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Energy Transfer Equity, L.P.