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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 March 31, 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  ¨    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 May 4, 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 – March 31, 2010 and December 31, 2009		1
Condensed Consolidated Statements of Operations – Three Months Ended March 31, 2010 and 2009		3
Condensed Consolidated Statements of Comprehensive Income – Three Months Ended March  31, 2010 and 2009		4
Condensed Consolidated Statement of Equity – Three Months Ended March 31, 2010		5
Condensed Consolidated Statements of Cash Flows – Three Months Ended March 31, 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		35
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		48
ITEM 4. CONTROLS AND PROCEDURES		50
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		51
ITEM 1A. RISK FACTORS		51
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		51
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		51
ITEM 4. [RESERVED]
ITEM 5. OTHER INFORMATION		51
ITEM 6. EXHIBITS		52
SIGNATURE		54

 

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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 within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”). 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 expectations 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 as well as 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)

 

		March 31, 2010				December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	384,429			$	68,315
Marketable securities			3,726				6,055
Accounts receivable, net of allowance for doubtful accounts			490,475				566,522
Accounts receivable from related companies			45,884				51,894
Inventories			342,976				389,954
Exchanges receivable			7,815				23,136
Price risk management assets			19,575				12,371
Other current assets			117,317				149,712
Total current assets			1,412,197				1,267,959
PROPERTY, PLANT AND EQUIPMENT			10,274,322				10,117,041
ACCUMULATED DEPRECIATION			(1,098,943	)			(1,052,566	)
			9,175,379				9,064,475
ADVANCES TO AND INVESTMENTS IN AFFILIATES			653,390				663,298
GOODWILL			802,587				775,094
INTANGIBLES AND OTHER ASSETS, net			447,568				389,683
Total assets		$	12,491,121			$	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)

 

		March 31, 2010				December 31, 2009
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	344,920			$	359,176
Accounts payable to related companies			20,850				38,515
Exchanges payable			9,545				19,203
Price risk management liabilities			60,677				65,146
Accrued and other current liabilities			367,989				366,781
Current maturities of long-term debt			166,896				40,924
Total current liabilities			970,877				889,745
LONG-TERM DEBT, less current maturities			7,465,027				7,750,998
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES			105,794				73,332
OTHER NON-CURRENT LIABILITIES			226,552				226,183
COMMITMENTS AND CONTINGENCIES (Note 14)
			8,768,250				8,940,258
EQUITY:
PARTNERS’ CAPITAL:
General Partner			536				368
Limited Partners:
Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at March 31, 2010 and December 31, 2009, respectively)			107,918				53,412
Accumulated other comprehensive loss			(48,148	)			(53,628	)
Total partners’ capital			60,306				152
Noncontrolling interest			3,662,565				3,220,099
Total equity			3,722,871				3,220,251
Total liabilities and equity		$	12,491,121			$	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 March 31,
		2010				2009
REVENUES:
Natural gas operations		$	1,306,709			$	1,111,955
Retail propane			533,439				487,907
Other			31,833				30,112
Total revenues			1,871,981				1,629,974
COSTS AND EXPENSES:
Cost of products sold — natural gas operations			912,606				732,113
Cost of products sold — retail propane			304,981				220,222
Cost of products sold — other			7,278				6,804
Operating expenses			170,748				181,773
Depreciation and amortization			86,331				75,659
Selling, general and administrative			51,109				57,305
Total costs and expenses			1,533,053				1,273,876
OPERATING INCOME			338,928				356,098
OTHER INCOME (EXPENSE)
Interest expense, net of interest capitalized			(121,671	)			(101,391	)
Equity in earnings of affiliates			6,181				497
Losses on disposal of assets			(1,864	)			(426	)
Gains (losses) on non-hedged interest rate derivatives			(14,424	)			10,051
Allowance for equity funds used during construction			1,309				20,427
Other, net			834				701
INCOME BEFORE INCOME TAX EXPENSE			209,293				285,957
Income tax expense			5,211				6,207
NET INCOME			204,082				279,750
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST			91,305				128,214
NET INCOME ATTRIBUTABLE TO PARTNERS			112,777				151,536
GENERAL PARTNER’S INTEREST IN NET INCOME			349				469
LIMITED PARTNERS’ INTEREST IN NET INCOME		$	112,428			$	151,067
BASIC NET INCOME PER LIMITED PARTNER UNIT		$	0.50			$	0.68
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING			222,941,108				222,898,065
DILUTED NET INCOME PER LIMITED PARTNER UNIT		$	0.50			$	0.68
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING			222,941,108				222,898,065

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

(Dollars in thousands)

(unaudited)

 

		Three Months Ended March 31,
		2010				2009
Net income		$	204,082			$	279,750
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges			830				(5,645	)
Change in value of derivative instruments accounted for as cash flow hedges			23,803				(6,587	)
Change in value of available-for-sale securities			(2,329	)			51
			22,304				(12,181	)
Comprehensive income			226,386				267,569
Less: Comprehensive income attributable to noncontrolling interest			108,128				121,196
Comprehensive income attributable to partners		$	118,258			$	146,373

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 THREE MONTHS ENDED MARCH 31, 2010

(Dollars in thousands)

(unaudited)

 

		General         Partner				Common     Unitholders				Accumulated Other Comprehensive Loss				Noncontrolling Interest				Total
Balance, December 31, 2009		$	368			$	53,412			$	(53,628	)		$	3,220,099			$	3,220,251
Distributions to ETE partners			(374	)			(120,388	)			—				—				(120,762	)
Subsidiary distributions			—				—				—				(114,369	)			(114,369	)
Subsidiary units issued for cash			193				62,232				—				442,055				504,480
Tax effect of remedial income allocation from tax amortization of goodwill			—				—				—				(851	)			(851	)
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings			—				228				—				7,196				7,424
Non-cash executive compensation			—				6				—				306				312
Other comprehensive income, net of tax			—				—				5,480				16,824				22,304
Net income			349				112,428				—				91,305				204,082
Balance, March 31, 2010		$	536			$	107,918			$	(48,148	)		$	3,662,565			$	3,722,871

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)

 

		Three Months Ended March 31,
		2010				2009
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	475,040			$	412,970
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired			(149,619	)			(5,511	)
Capital expenditures (excluding allowance for equity funds used during construction)			(119,721	)			(263,819	)
Contributions in aid of construction costs			2,174				1,877
Advances to affiliates, net of repayments			(50	)			(119,850	)
Proceeds from the sale of assets			1,074				2,925
Net cash used in investing activities			(266,142	)			(384,378	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			89,388				511,180
Principal payments on debt			(251,521	)			(549,817	)
Subsidiary equity offering, net of issue costs			504,480				225,863
Distributions to partners			(120,762	)			(114,031	)
Debt issuance costs			—				(173	)
Distributions to noncontrolling interests			(114,369	)			(87,199	)
Net cash provided by (used in) financing activities			107,216				(14,177	)
INCREASE IN CASH AND CASH EQUIVALENTS			316,114				14,415
CASH AND CASH EQUIVALENTS, beginning of period			68,315				92,023
CASH AND CASH EQUIVALENTS, end of period		$	384,429			$	106,438

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:

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 Energy Transfer Equity, L.P., and its subsidiaries (the “Partnership,” “ETE” or the “Parent Company”) as of March 31, 2010 and for the three months ended March 31, 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.

The unaudited condensed consolidated financial statements of the Partnership presented herein for the three-month periods ended March 31, 2010 and 2009 include the results of operations of ETE, ETE’s controlled subsidiary, Energy Transfer Partners, L.P., a publicly-traded master limited partnership (“ETP”), and ETE’s wholly-owned subsidiaries: Energy Transfer Partners GP, L.P., the General Partner of ETP (“ETP GP”), and Energy Transfer Partners, L.L.C., the General Partner of ETP GP (“ETP LLC”). The results of operations for ETP in turn include the results of operations for ETP’s wholly-owned subsidiaries described below under “Business Operations.” LE GP, LLC (“LE GP”), the general partner of ETE, is a Delaware limited liability company, which is ultimately owned by the Chief Executive Officer of ETP, a director of ETE (Mr. Ray Davis) and Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”).

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 Energy Transfer Equity, L.P. and its subsidiaries as of March 31, 2010, and the Partnership’s results of operations and cash flows for the three months ended March 31, 2010 and 2009. The unaudited interim condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Equity 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.

Business Operations

The Parent Company currently has no separate operating activities apart from those conducted by the Operating Companies. 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.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company-only assets and liabilities of ETE are not available to satisfy the debts and other obligations of ETP and its consolidated subsidiaries. In order to fully understand the financial condition of the Partnership on a stand-alone basis, see Note 18 for stand-alone financial information apart from that of the consolidated partnership information included herein.

 

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In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we conduct business, our activities are primarily conducted through ETP’s operating subsidiaries (collectively the “Operating Companies”) as follows:

 

•

La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”), a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico, Utah and Colorado. Our intrastate transportation and storage operations primarily focus on transporting natural gas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. Our midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System and North Texas System, and marketing activities. We also own and operate natural gas gathering pipelines and conditioning facilities in the Piceance-Uinta Basin of Colorado and Utah.

 

•

Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”), both of which are Delaware limited liability companies engaged in interstate transportation of natural gas. Interstate revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.

 

•

ETC Fayetteville Express Pipeline, LLC (“ETC FEP”), a Delaware limited liability company formed to engage in interstate transportation of natural gas.

 

•

ETC Tiger Pipeline, LLC (“ETC Tiger”), a Delaware limited liability company formed to engage in interstate transportation of natural gas.

 

•

ETC Compression, LLC (“ETC Compression”), a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

 

•

Heritage Operating, L.P. (“HOLP”), a Delaware limited partnership primarily engaged in retail propane operations. Our retail propane operations focus on sales of propane and propane-related products and services. The retail propane customer base includes residential, commercial, industrial and agricultural customers.

 

•

Titan Energy Partners, L.P. (“Titan”), a Delaware limited partnership also engaged in retail propane operations.

The Partnership, the Operating Companies and their subsidiaries are collectively referred to in this report as “we,” “us,” “ETE,” “ETP,” “Energy Transfer” or the “Partnership.” References to “the Parent Company,” are to mean Energy Transfer Equity, L.P. on a stand-alone basis.

 

2.	ESTIMATES:

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.

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 segments 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 operating results estimated for the three months ended March 31, 2010 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.

 

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3.	ACQUISITIONS:

During the three months ended March 31, 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 7.

 

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 which are subject to an insignificant risk of changes in value.

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

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

 

 

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Non-cash investing and financing activities and supplemental cash flow information are as follows:

 

 

5.	ACCOUNTS RECEIVABLE:

Accounts receivable consisted of the following:

 

The activity in the allowance for doubtful accounts consisted of the following:

 

Balance, December 31, 2009		$	6,338
Accounts receivable written off, net of recoveries			(856	)
Provision for loss on accounts receivable			883
Balance, March 31, 2010		$	6,365

 

6.	INVENTORIES:

Inventories consisted of the following:

 

		March 31, 2010			December 31, 2009
Natural gas and NGLs, excluding propane		$	33,930		$	157,103
Propane			48,080			66,686
Appliances, parts and fittings and other			260,966			166,165
Total inventories		$	342,976		$	389,954

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. We designate commodity 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 have been recorded in cost of products sold in our condensed consolidated statements of operations.

 

7.	GOODWILL, INTANGIBLES AND OTHER ASSETS:

A net increase in goodwill of $27.5 million was recorded during the three months ended March 31, 2010, primarily due to $27.3 million from the acquisition of the natural gas gathering company referenced in Note 3, which is expected to be deductible for tax purposes. In addition, we recorded customer contracts of $68.2 million with useful lives of 46 years.

 

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

 

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

 

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

 

Years Ending December 31:
2011		$	29,055
2012			23,620
2013			17,812
2014			16,802
2015			14,479

 

8.	FAIR VALUE MEASUREMENTS:

The carrying amounts of 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 March 31, 2010 was $8.29 billion and $7.63 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 and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable

 

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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. We currently do not have any recurring fair value measurements that are considered Level 3 valuations.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of March 31, 2010 and December 31, 2009 based on inputs used to derive their fair values:

 

 

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9.	INVESTMENTS IN AFFILIATES:

Midcontinent Express Pipeline LLC

ETP is 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 in Butler, Alabama. Interim service began on the pipeline from Bennington, Oklahoma, to Delhi in April 2009. In July 2008, Midcontinent Express Pipeline LLC (“MEP”), the entity formed to construct, own and operate this pipeline, completed an open season with respect to a capacity expansion of the pipeline from the current capacity of 1.4 Bcf/d to a total capacity of 1.8 Bcf/d for the main segment of the pipeline from north Texas to an interconnect location with the Columbia Gas Transmission Pipeline near Waverly, Louisiana. The additional capacity was fully subscribed as a result of this open season. The planned expansion of capacity will be added through the installation of additional compression on this segment of the pipeline and is expected to be completed as early as June 2010. This expansion was approved by the Federal Energy Regulatory Commission (the “FERC”) in September 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 FERC on March 25, 2009.

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. That order is currently subject to a limited request for rehearing. The pipeline is expected to have an initial capacity of 2.0 Bcf/d and is expected to be in service by the end of 2010. As of March 31, 2010, FEP has secured binding 10-year commitments 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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Summarized Financial Information

The following table presents aggregated selected income statement data for our unconsolidated affiliates, MEP and FEP (on a 100% basis):

 

As stated above, MEP was placed into service during 2009.

 

10.	NET INCOME PER LIMITED PARTNER UNIT:

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

 

 

11.	DEBT OBLIGATIONS:

Revolving Credit Facilities

Parent Company Facilities

The Parent Company has a $1.45 billion Term Loan Facility with a Term Loan Maturity Date of November 1, 2012 (the “Parent Company Credit Agreement”). The Parent Company Credit Agreement also includes a $500.0 million Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of March 31, 2010 was $1.58 billion. The total amount available under the Parent Company’s debt facilities as of March 31, 2010 was $374.0 million. The Parent Company Revolving Credit Facility also contains an accordion feature, which will allow the Parent Company, subject to bank syndication’s approval, to expand the facility’s capacity up to an additional $100.0 million.

 

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The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio, which is currently at Level I or 0.3%. Loans under the Parent Company Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. As of March 31, 2010, the weighted average interest rate was 1.94% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $1.45 billion Senior Secured Term Loan Facility.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries, including its ownership of 62,500,797 ETP Common Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s General Partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights (“IDRs”) in ETP, which the Parent Company holds through its ownership of ETP GP.

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 Amended and Restated Credit Agreement). 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 a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating and the fee is 0.11% based on our current rating with a maximum fee of 0.125%.

As of March 31, 2010, there was no balance outstanding on the ETP Credit Facility, and taking into account letters of credit of approximately $62.2 million, $1.94 billion was available for future borrowings.

HOLP Credit Facility

HOLP 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 a 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 March 31, 2010, there was no outstanding balance in revolving credit loans and outstanding letters of credit of $1.0 million. The amount available for borrowing as of March 31, 2010 was $74.0 million.

Covenants Related to Our Credit Agreements

We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements at March 31, 2010.

 

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12.	PARTNERS’ CAPITAL:

Common Units Issued

The change in Common Units during the three months ended March 31, 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, March 31, 2010		222,941,172

Sale of Common Units by Subsidiary

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and the underlying book value arising from issuance of units by ETP (excluding unit issuances to the Parent Company) as a capital transaction. If ETP issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment in ETP 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 Common Units during the three months ended March 31, 2010.

In January 2010, ETP issued 9,775,000 ETP Common Units through a public offering. The proceeds of $423.6 million from the offering were used primarily to repay borrowings under ETP’s revolving 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 three months ended March 31, 2010, ETP issued 1,760,783 ETP Common Units pursuant to this agreement. In addition, ETP initiated trades on 326,633 ETP Common Units that had not settled as of March 31, 2010. The proceeds of approximately $81.0 million, net of commissions, were used for general partnership purposes. Approximately $134.8 million remains available to be issued under the agreement as of March 31, 2010.

As a result of ETP’s issuance of ETP Common Units, we have recognized increases in partners’ capital of $62.4 million for the three months ended March 31, 2010.

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 related to limited and general partnership interests, including IDRs in ETP. We currently have no independent operations outside of our interests in ETP.

On February 19, 2010, the Parent Company paid a cash distribution for the three months ended December 31, 2009 of $0.54 per Common Unit, or $2.16 annualized, to Unitholders of record at the close of business on February 8, 2010.

On April 27, 2010, the Parent Company announced the declaration of a cash distribution for the three months ended March 31, 2010 of $0.54 per Common Unit, or $2.16 annualized. This distribution will be paid on May 19, 2010 to Unitholders of record at the close of business on May 7, 2010.

 

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

 

		Three Months Ended March 31,
		2010			2009
Limited Partners		$	120,388		$	117,021
General Partner			374			363
Total distributions declared		$	120,762		$	117,384

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.

On February 15, 2010, ETP paid a cash distribution for the three months ended December 31, 2009 of $0.89375 per Common Unit, or $3.575 annualized to Unitholders of record at the close of business on February 8, 2010.

The total amount of distributions the Parent Company received from ETP for the three months ended March 31, 2010 relating to its limited partner interests, general partner interests and IDRs of ETP are as follows:

 

		Three Months Ended March 31,
		2010			2009
Limited Partners		$	55,860		$	55,860
General Partner Interest			4,880			4,860
Incentive Distribution Rights			94,917			84,146
Total distributions received from ETP		$	155,657		$	144,866

On April 27, 2010, ETP declared a cash distribution for the three months ended March 31, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on May 17, 2010 to Unitholders of record at the close of business on May 7, 2010.

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

 

		Three Months Ended March 31,
		2010			2009
Limited Partners:
Common Units		$	170,921		$	150,853
Class E Units			3,121			3,121
General Partner Interest			4,880			4,860
Incentive Distribution Rights			94,917			84,146
Total distributions declared by ETP		$	273,839		$	242,980

 

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Accumulated Other Comprehensive Income (Loss)

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

 

 

13.	INCOME TAXES:

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

 

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

 

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

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. In February 2010, ETP announced a 400 MMcf/d expansion, subject to FERC approval.

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 is required to file a new rate case no later than October 1, 2011.

 

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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. Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage 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 a 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.

The commitment amount under the MEP Facility was $255.4 million as of March 31, 2010 and it had $89.0 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. ETP’s contingent obligations with respect to its 50% guarantee of MEP’s outstanding borrowings and letters of credit were $44.5 million and $16.6 million, respectively, as of March 31, 2010. The weighted average interest rate on the total amount outstanding as of March 31, 2010 was 1.5%. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions.

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 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 a 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 March 31, 2010, FEP had $468.0 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 $234.0 million as of March 31, 2010. The weighted average interest rate on the total amount outstanding as of March 31, 2010 was 3.2%.

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 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.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $5.9 million and $6.0 million for the three months ended March 31, 2010 and 2009, respectively.

Titan has an agreement with Enterprise (see Note 16) to purchase the majority of Titan’s propane requirements. The contract expired in March 2010 and contains renewal and extension options that are currently under negotiation.

We have commitments to make capital contributions to our joint ventures. For the joint ventures that we currently have interests in, we expect that capital contributions for the remainder of 2010 will be between $100 million and $120 million.

 

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Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and 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/CFTC 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. In its Order and Notice, the FERC also alleged that ETP manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates. 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. The FERC specified that it was also seeking to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at market-based prices. 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.

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 settles 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 against ETP, including existing litigation claims as well as any new claims that may be asserted against this fund. An administrative law judge appointed by the FERC will determine the validity of any third party claim against this fund. Any party who receives money from this fund will be required to waive all claims against ETP related to this matter. 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.

ETP made the $5.0 million payment and established the $25.0 million fund in October 2009. The judge issued his report in March 2010 recommending the allocation of the $25.0 million fund. We expect a final decision on the allocation of the $25.0 million fund in 2010.

In addition to the FERC legal action, third parties have asserted claims and may assert additional claims against us and ETP alleging damages related to these matters. In this regard, several natural gas producers and a natural gas marketing company have initiated legal proceedings in Texas state courts against us and ETP for claims related to the FERC claims. These suits contain 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, and seek unspecified direct, indirect, consequential and exemplary damages. One of the suits

 

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against us and ETP contains an additional allegation that we and ETP transported gas in a manner that favored our affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. We have moved to compel arbitration and/or contested subject-matter jurisdiction in some of these cases. In one of these cases, the Texas Supreme Court ruled on July 3, 2009 that the state district court erred in ruling that a plaintiff was entitled to pre-arbitration discovery and therefore remanded to the state district court with a direction to rule on our original motion to compel arbitration pursuant to the terms of the arbitration clause in a natural gas contract between us and the plaintiff. This plaintiff has filed a motion with the Texas Supreme Court requesting a rehearing of the ruling.

We have also been served with a complaint from an owner of royalty interests in natural gas producing properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producer/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. We filed an original action in Harris County state court seeking a stay of the arbitration on the ground that the action is not arbitrable, and the state court granted our motion for summary judgment on that issue. This action is currently on appeal before the First Court of Appeals, Houston, Texas.

A consolidated class action complaint has been filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the NYMEX in violation of the Commodity Exchange Act (“CEA”). It is further alleged that during the class period December 29, 2003 to December 31, 2005, ETP had the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, in order to benefit ETP’s natural gas physical and financial trading positions, and that ETP intentionally submitted price and volume trade information to trade publications. This complaint also alleges that ETP violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified damages to the plaintiffs and all other members of the putative class who sold natural gas futures or who purchased and/or sold natural gas options contracts on NYMEX during the class period. The plaintiffs have requested certification of their suit as a class action and seek unspecified damages, court costs and other appropriate relief. On January 14, 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. On March 20, 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, on May 5, 2008, ETP filed a motion to dismiss the complaint. On March 26, 2009, the court issued an order dismissing the complaint, with prejudice, for failure to state a claim. On April 9, 2009, the plaintiffs moved for reconsideration of the order dismissing the complaint, and on August 26, 2009, the court denied the plaintiffs’ motion for reconsideration. On September 24, 2009, the plaintiffs filed a Notice of Appeal with the U.S. Court of Appeals for the Fifth Circuit. Briefing is complete and the case was argued before the Fifth Circuit on April 28, 2010.

On March 17, 2008, a second class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period ETP exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit its own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks unspecified treble damages, court costs and other appropriate relief. On May 19, 2008, ETP filed a motion to dismiss this complaint. On March 26, 2009, the court issued an order dismissing the complaint. The court found that the plaintiffs failed to state a claim on all causes of action and for anti-trust injury, but granted leave to amend. On April 23, 2009, the plaintiffs filed a motion for leave to amend to assert a claim for common law fraud, and attached a proposed amended complaint as an exhibit. ETP opposed the motion and cross-moved to dismiss. On August 7, 2009, the court denied the plaintiff’s motion and granted ETP’s motion to dismiss the complaint. On September 8, 2009, the plaintiff filed its Notice of Appeal with the U.S. Court of Appeals for the Fifth Circuit. Briefing is now complete, and the case was argued before the Fifth Circuit on April 27, 2010.

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 record 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. ETP expects the after-tax cash impact of the settlement to be less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims, which ETP expects to realize in future periods. Although this

 

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payment covers the $25.0 million required by the settlement agreement to be applied to resolve third party claims, including the existing third party litigation described above, it is possible that the amount ETP becomes obliged to pay to resolve third party litigation related to these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of the payment related to these matters. In accordance with applicable accounting standards, ETP will review the amount of our accrual related to these matters as developments related to these matters occur and ETP will adjust its accrual if ETP determines that it is probable that the amount it may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of our accrual for these matters. As ETP’s accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce ETP’s cash available to service our indebtedness either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, ETP may experience a material adverse impact on its results of operations and our liquidity.

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 engaged in ongoing 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”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have 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. AEP is appealing the court decision. Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP does not expect that it will be liable for any portion of this court award.

Other Matters. In addition to those matters described above, we or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As of March 31, 2010 and December 31, 2009, accruals of approximately $10.5 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 March 31, 2010 or December 31, 2009 consolidated balance sheets for our contingencies and current litigation matters, excluding accruals related to environmental matters.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and 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 and processing business, and there can be no assurance that

 

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significant costs and liabilities will not be incurred. 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 health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.

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 by polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2018 is $8.5 million. 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 (“SPCC”) 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.

In July 2001, HOLP acquired a company that had previously received a request for information from the EPA regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). We have not received any follow-up correspondence from the EPA on the matter since our acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.

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 March 31, 2010 or December 31, 2009 consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

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 cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

As of March 31, 2010 and December 31, 2009, accruals on an undiscounted basis of $12.6 million were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition, the Transwestern acquisition, and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors.

 

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

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 March 31, 2010 and 2009, $1.4 million and $3.7 million, respectively, of capital costs and $1.9 million and $3.4 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

 

15.	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

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 consolidated balance sheets. In general, we use derivatives to eliminate market exposure and price risk within our segments as follows:

 

•

Derivatives are utilized in our midstream segment in order to mitigate price volatility in our marketing activities and manage fixed price exposure incurred from contractual obligations.

 

•

We use derivative financial instruments in connection with our 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. We also use derivatives in our intrastate transportation and storage segment to hedge the sales price of retention gas and hedge location price differentials related to the transportation of natural gas.

 

•

Our propane segment permits customers to guarantee the propane delivery price for the next heating season. As we execute fixed sales price contracts with our customers, we may enter into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin. Additionally, we may use propane futures contracts to secure the purchase price of our propane inventory for a percentage of our anticipated propane sales.

We inject and hold natural gas in our 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. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we 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 we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices along with the financial derivative we use 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 our derivative instruments using marked to market accounting, with changes in the fair value of our 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, we will record unrealized gains or lower unrealized losses. If the spread widens, we will

 

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record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread, through either mark-to-market or the physical withdrawal of natural gas.

We are also exposed to market risk on gas we retain for fees in our intrastate transportation and storage segment. We use financial derivatives to hedge the sales price of this gas, including futures, swaps and options. For certain contracts that qualify for hedge accounting, we designate them as cash flow hedges of the forecasted sale of 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 consolidated statement of operations.

We attempt to maintain balanced positions in our marketing activities to protect ourselves 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 our 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 our positions. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial position and results of operations, either favorably or unfavorably.

The following table details the outstanding commodity-related derivatives:

 

We expect gains of $24.5 million related to commodity derivatives to be reclassified into earnings over the next year related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage a portion of our current and

 

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future interest rate exposures by utilizing interest rate swaps in order to achieve our desired mix of fixed and variable rate debt. We have the following interest rate swaps outstanding as of March 31, 2010:

 

Term		Notional Amount			Type (1)		Hedge Designation
May 2016		$	300,000		Pay an averaged fixed rate of 5.20% and receive a floating rate		Undesignated
November 2012 (2)			500,000		Pay a fixed rate of 4.57% and receive a floating rate		Undesignated
November 2012			700,000		Pay an averaged fixed rate of 4.84% and receive a floating rate		Cash flow
July 2013			350,000		Pay a floating rate and receive a fixed rate of 6.00%		Fair value
February 2015			750,000		Pay a floating rate and receive a fixed rate of 5.95%		Fair value

 

(1)

Floating rates are based on LIBOR.

 

(2)

Term includes a cancellable option in November 2010.

Derivative Summary

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

 

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.

We utilize 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 our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date for non-exchange traded derivatives. We exchange 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. The Partnership had net deposits with counterparties of $66.8 million and $79.7 million as of March 31, 2010 and December 31, 2009, respectively.

 

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The following tables detail the effect of the Partnership’s derivative assets and liabilities in the condensed consolidated statements of operations for the periods presented:

 

 

 

 

 

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We recognized $8.8 million and $73.2 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the three months ended March 31, 2010 and 2009, respectively.

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 its overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. 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 consolidated balance sheet and recognized in net income or other comprehensive income.

 

16.	RELATED PARTY TRANSACTIONS:

ETC OLP and Enterprise GP Holdings L.P. (“Enterprise”) transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ETC OLP sells natural gas to Enterprise. Our propane operations routinely buy and sell product with Enterprise. The following table presents sales to and purchase from affiliates of Enterprise:

 

 

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Titan purchases the majority of its propane requirements from Enterprise pursuant to an agreement that expired in March 2010, and contains renewal and extension options that are currently under negotiation. As of December 31, 2009, Titan had forward mark-to-market derivatives for approximately 6.1 million gallons of propane at a fair value asset of $3.3 million with Enterprise. Substantially all of these forward contracts were settled as of March 31, 2010. In addition, as of March 31, 2010 and December 31, 2009, Titan had forward derivatives accounted for as cash flow hedges of 6.6 million and 20.5 million gallons of propane at a fair value asset of $0.7 million and $8.4 million, respectively, with Enterprise.

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

 

Accounts receivable from related companies excluding Enterprise consist of the following:

 

 

17.	REPORTABLE SEGMENTS:

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

•        natural gas operations:

     o        intrastate transportation and storage

     o        interstate transportation

     o        midstream

•        retail propane and other retail propane related operations

 

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We evaluate the performance of our operating segments based on operating income exclusive of general partnership selling, general and administrative expenses. The following tables present the financial information by segment for the following periods:

 

 

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18.	SUPPLEMENTAL INFORMATION:

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

BALANCE SHEETS

(unaudited)

 

		March 31, 2010				December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	62			$	62
Accounts receivable from related companies			—				97
Other current assets			1,685				1,287
Total current assets			1,747				1,446
ADVANCES TO AND INVESTMENT IN AFFILIATES			1,783,619				1,711,928
INTANGIBLES AND OTHER ASSETS, net			4,823				5,574
Total assets		$	1,790,189			$	1,718,948
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable		$	163			$	178
Accounts payable to affiliates			6,167				5,024
Price risk management liabilities			60,677				64,704
Accrued and other current liabilities			1,423				1,607
Current maturities of long-term debt			126,006				—
Total current liabilities			194,436				71,513
LONG-TERM DEBT, less current maturities			1,450,000				1,573,951
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES			85,447				73,332
COMMITMENTS AND CONTINGENCIES
			1,729,883				1,718,796
PARTNERS’ CAPITAL:
General Partner			536				368
Limited Partners – Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at March 31, 2010 and December 31, 2009, respectively)			107,918				53,412
Accumulated other comprehensive loss			(48,148	)			(53,628	)
Total partners’ capital			60,306				152
Total liabilities and partners’ capital		$	1,790,189			$	1,718,948

 

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STATEMENTS OF OPERATIONS

(unaudited)

 

		Three Months Ended March 31,
		2010				2009
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES		$	(2,336	)		$	(1,687	)
OTHER INCOME (EXPENSE):
Interest expense			(16,706	)			(19,342	)
Equity in earnings of affiliates			146,378				176,593
Losses on non-hedged interest rate derivatives			(14,424	)			(3,675	)
Other, net			(124	)			(353	)
INCOME BEFORE INCOME TAXES			112,788				151,536
Income tax expense			11				—
NET INCOME ATTRIBUTABLE TO PARTNERS			112,777				151,536
GENERAL PARTNER’S INTEREST IN NET INCOME			349				469
LIMITED PARTNERS’ INTEREST IN NET INCOME		$	112,428			$	151,067

 

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STATEMENTS OF CASH FLOWS

(unaudited)

 

		Three Months Ended March 31,
		2010				2009
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES		$	118,864			$	114,604
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings			11,421				23,792
Principal payments on debt			(9,523	)			(24,015	)
Distributions to Partners			(120,762	)			(114,031	)
Net cash used in financing activities			(118,864	)			(114,254	)
INCREASE IN CASH AND CASH EQUIVALENTS			—				350
CASH AND CASH EQUIVALENTS, beginning of period			62				62
CASH AND CASH EQUIVALENTS, end of period		$	62			$	412

 

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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. 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 for the year ended December 31, 2009.

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

Overview

Currently, our business operations are conducted only through ETP’s Operating Companies (collectively referred to as the “Operating Companies”), which include ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and natural gas storage operations, Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”), a Delaware limited liability company engaged in interstate transportation of natural gas, and ETC Midcontinent Express Pipeline, LLC (“ETC MEP” or “MEP”), a Delaware limited liability company engaged in interstate transportation of natural gas, and HOLP and Titan, both Delaware limited partnerships engaged in retail propane operations.

Parent Company – Energy Transfer Equity, L.P.

The principal sources of cash flow for the Parent Company are distributions it receives from its direct and indirect investments in limited and general partner interests of ETP. The Parent Company’s primary cash requirements are for distributions to its partners, 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 or the Operating Companies. In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

General

Our primary objective is to increase the level of our cash distributions to our partners over time by pursuing a business strategy that is currently focused on growing our natural gas midstream and intrastate transportation and storage businesses (including transportation, gathering, compression, treating, processing, storage and marketing) and our propane business through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain additional businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash ETP generates from operations.

During the past several years, ETP has been successful in completing several transactions that have been accretive to our Unitholders, including the combination of the retail propane operations of Heritage Propane Partners, L.P. and the midstream and intrastate transportation and storage operations of ETC OLP in January 2004. We have also made, and are continuing to make, significant investments in internal growth projects, primarily the construction of pipelines, gathering systems and natural gas treating and processing plants, which we believe will provide additional cash flow to our Unitholders for years to come.

Our principal operations are conducted in the following segments:

 

•

Intrastate transportation and storage — Revenue is principally generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. Our interruptible or short-term business is generally impacted by basis differentials between delivery points on our system and the price of natural gas. The basis differentials that primarily impact our interruptible business are receipt points between west Texas to east Texas. When basis differentials widen, our interruptible volumes and fees generally increase. The fee

 

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structure normally consists of a monetary fee and/or fuel retention. Excess fuel retained after consumption is sold at market prices. In addition to transport fees, our HPL System generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies.

We generate fee-based revenue from our natural gas storage facilities by contracting with third parties for their use of our storage capacity. From time to time, we utilize any excess storage capacity to inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, a term used to describe a pricing environment when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market and entering into a financial derivative to lock in the forward sale price. If we designate the related financial derivative as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices whereas the financial derivative is valued using forward natural gas prices. As a result of fair value hedge accounting, we have elected to exclude the spot forward premium from the measurement of effectiveness and changes in the spread between forward natural gas prices and spot market prices result in unrealized gains or losses until the underlying physical gas is withdrawn and the related financial 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. If the spread narrows between spot and forward prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains.

In addition to hedging our stored natural gas, we also use financial derivatives to lock in prices on a portion of our estimated volumes exposed to natural gas price risk within our intrastate transportation segment.

During 2010, we continued to enter into financial derivatives to lock in spreads on a portion of our transportation system’s open capacity. Margins earned on that open capacity are dependent on price differentials at different points on our system, generally from West Texas to East Texas. We account for these financial derivatives using mark-to-market accounting and the change in value of these derivatives are recorded in earnings. As of March 31, 2010, approximately 19% of our intrastate transportation capacity is hedged.

 

•

Interstate transportation — Revenue is primarily generated by fees earned from natural gas transportation services and operational gas sales.

 

•

Midstream — Revenue is principally dependent upon the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines as well as the level of natural gas and NGL prices.

In addition to fee-based contracts for gathering, treating and processing, we also have percent of proceeds and keep-whole contracts, which are subject to market pricing. For percent of proceeds contracts (which accounted for approximately 11% of total processed volumes for the three months ended March 31, 2010 and 2009, respectively), we retain a portion of the natural gas and NGLs processed as a fee. When natural gas and NGL pricing increase, the value of the portion we retain as a fee increases. Conversely, when prices of natural gas and NGL’s decrease, so does the value of the portion we retain as a fee. For keep-whole contracts (which accounted for approximately 34% and 26% of total processed volumes for the three months ended March 31, 2010 and 2009, respectively), we retain the difference between the price of NGLs and the cost of the gas to process it. In periods of high NGL prices relative to natural gas, our margins increase. During periods of low NGL prices relative to natural gas, our margins decrease or could be negative. In the event it is uneconomical to process this gas, we have the ability to bypass our processing plants to avoid negative margins that may occur from processing NGLs.

We conduct marketing operations in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

 

•

Retail propane and other retail propane related operations — Revenue is principally generated from the sale of propane and propane-related products and services.

 

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Results of Operations

Parent Company Results

The Parent Company currently has no separate operating activities apart from those conducted by ETP and its Operating Companies. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner interests of ETP.

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

 

		Three Months Ended March 31,
		2010				2009				Change
Equity in earnings of affiliates		$	146,378			$	176,593			$	(30,215	)
Selling, general and administrative			(2,336	)			(1,687	)			(649	)
Interest expense, net of interest capitalized			(16,706	)			(19,342	)			2,636
Losses on non-hedged interest rate derivatives			(14,424	)			(3,675	)			(10,749	)
Other, net			(124	)			(353	)			229

The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its ownership of ETP GP and its ownership of ETP LLC. The decrease in equity in earnings of affiliates was directly related to the changes in consolidated results and ETP segment income described below.

Interest Expense. Interest expense decreased primarily due to a decrease in the LIBOR rate between periods.

Losses on Non-Hedged Interest Rate Derivatives. The Parent Company has interest swaps that are not accounted for as hedges. Changes in the fair value of these swaps are recorded directly in earnings. The variable portion of these swaps is based on the three month LIBOR and its corresponding forward curve. Increases or decreases in gains or 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.

Consolidated Results

 

		Three Months Ended March 31,
		2010				2009				Change
Revenues		$	1,871,981			$	1,629,974			$	242,007
Cost of products sold			1,224,865				959,139				265,726
Gross margin			647,116				670,835				(23,719	)
Operating expenses			170,748				181,773				(11,025	)
Depreciation and amortization			86,331				75,659				10,672
Selling, general and administrative			51,109				57,305				(6,196	)
Operating income			338,928				356,098				(17,170	)
Interest expense, net of interest capitalized			(121,671	)			(101,391	)			(20,280	)
Equity in earnings of affiliates			6,181				497				5,684
Losses on disposal of assets			(1,864	)			(426	)			(1,438	)
Gains (losses) on non-hedged interest rate derivatives			(14,424	)			10,051				(24,475	)
Allowance for equity funds used during construction			1,309				20,427				(19,118	)
Other, net			834				701				133
Income tax expense			(5,211	)			(6,207	)			996
Net income		$	204,082			$	279,750			$	(75,668	)

See the detailed discussion of revenues, costs of products sold, gross margin, operating expenses, and depreciation and amortization by operating segment below.

 

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Interest Expense. Interest expense increased principally due to issuances of senior notes in April and December 2009. Proceeds from the issuance of these notes were primarily used to finance growth capital expenditures in our intrastate transportation and storage and interstate transportation segments, including capital contributions to our joint ventures. Interest expense is presented net of capitalized interest and allowance for debt funds used during construction, which totaled $1.1 million and $5.9 million for the three months ended March 31, 2010 and 2009, respectively.

Equity in Earnings of Affiliates. The increase in equity in earnings of affiliates between the periods was primarily attributable to earnings of MEP, which was placed in service in 2009 (the first Zone in April 2009 and the second Zone in August 2009). We recorded equity in earnings of MEP of $5.5 million during 2010.

Gains (Losses) on Non-Hedged Interest Rate Derivatives. Non-hedged interest rate derivatives had a negative impact compared to the prior period as a result of the factors discussed above for the Parent Company results. In addition, ETP settled all of its non-hedged interest rate swaps during 2009 and is now accounting for its interest rate swaps as fair value hedges. ETP recognized gains of $13.7 million on its non-hedged interest rate swaps during the three months ended March 31, 2009.

Allowance for Equity Funds Used During Construction. The decrease in AFUDC on equity is due to the Phoenix project which was completed in February 2009. AFUDC on equity amounts recorded in property, plant and equipment (excluding AFUDC gross-up) were $1.3 million and $12.5 million for the three months ended March 31, 2010 and 2009, respectively.

Segment Operating Results

We evaluate segment performance based on operating income (either in total or by individual segment), which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

Detailed descriptions of our business and segments are included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on February 24, 2010.

Operating income (loss) by segment is as follows:

 

		Three Months Ended March 31,
		2010				2009				Change
Intrastate transportation and storage		$	132,135			$	141,645			$	(9,510	)
Interstate transportation			31,597				28,195				3,402
Midstream			51,346				24,153				27,193
Retail propane and other retail propane related			126,774				164,069				(37,295	)
All other			(1,131	)			(892	)			(239	)
Unallocated selling, general and administrative expenses			(1,793	)			(1,072	)			(721	)
Operating income		$	338,928			$	356,098			$	(17,170	)

Unallocated Selling, General and Administrative Expenses. Selling, general and administrative expenses are allocated monthly to the Operating Companies using the Modified Massachusetts Formula Calculation (“MMFC”). The expenses subject to allocation are based on estimated amounts and take into consideration actual expenses from previous months and known trends. The difference between the allocation and actual costs is adjusted in the following month, which results in over or under allocation of these costs due to timing differences.

 

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Intrastate Transportation and Storage

 

		Three Months Ended March 31,
		2010			2009			Change
Natural gas MMBtu/d — transported			11,354,270			13,623,212			(2,268,942	)
Natural gas MMBtu/d — sold			1,445,136			941,533			503,603
Revenues		$	866,492		$	628,651		$	237,841
Cost of products sold			641,506			382,614			258,892
Gross margin			224,986			246,037			(21,051	)
Operating expenses			41,961			53,490			(11,529	)
Depreciation and amortization			31,061			27,103			3,958
Selling, general and administrative			19,829			23,799			(3,970	)
Segment operating income		$	132,135		$	141,645		$	(9,510	)

Volumes. We experienced a decrease in volumes transported on our intrastate transportation systems due to less drilling activity and production by our customers in areas where our assets are located due to the low natural gas price environment and less favorable basis differentials. The increase in natural gas sold was a result of more withdrawals out of our Bammel storage facility as well as additional efforts to optimize our assets.

Gross Margin. The components of our intrastate transportation and storage segment gross margin were as follows:

 

		Three Months Ended March 31,
		2010			2009			Change
Transportation fees		$	140,798		$	175,133		$	(34,335	)
Natural gas sales and other			40,010			18,702			21,308
Retained fuel revenues			35,702			35,177			525
Storage margin, including fees			8,476			17,025			(8,549	)
Total gross margin		$	224,986		$	246,037		$	(21,051	)

Intrastate transportation and storage gross margin decreased primarily due to the following factors:

 

•

Volumes on our transportation pipelines decreased, resulting in a decrease in transportation fees of $34.3 million. This decrease primarily resulted from a narrowing of basis differentials between the west and east Texas market hubs, with the average spot price difference between these locations decreasing to $0.05/MMBtu from $0.62/MMBtu in the prior period.

 

•

Margin from natural gas sales and other activity increased by $21.3 million during the period primarily due to favorable impacts from system optimization activities. Excluding the derivatives related to storage, we recognized unrealized gains of $4.9 million for the three months ended March 31, 2010 compared to unrealized gains of $2.6 million for the three months ended March 31, 2009.

 

•

While our transported volumes were down and we retained less natural gas during the period, our retention revenue increased by $0.5 million principally due to more favorable pricing. Our average retention price during the period ended March 31, 2010 was $4.42/MMBtu compared to $3.31/MMBtu for the period ended March 31, 2009.

 

•

Storage margin decreased by $8.5 million, primarily due to less price variance between the carrying cost of our inventory and the locked-in sales price of our financial derivative. We apply fair value hedge accounting to the natural gas we purchase for storage and adjust the carrying amount to the spot price at the end of each period. Most of the margin that we realized for the natural gas that was withdrawn during the three months ended March 31, 2010 had been previously recognized through fair value adjustments and was therefore not reflected in the current period. The margin we recognized during the period was the remainder of the spread originally locked-in. Natural gas prices rose leading up to and during the withdrawal season. Therefore, we sold the natural gas to capture the margin on our gas held in storage. In the comparable period last year, it was advantageous to recognize the locked-in spread on the derivatives used to hedge the inventory and postpone the withdrawal as natural gas prices were declining.

 

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Storage margin was comprised of the following:

 

		Three Months Ended March 31,
		2010				2009
Withdrawals from storage natural gas inventory (MMBtu)			27,016,787				11,254,403
Margin on physical sales		$	64,378			$	(11,166	)
Fair value/lower of cost or market adjustment			(68,555	)			(44,621	)
Settlements of financial derivatives			(10,499	)			166,246
Unrealized gains (losses) on derivatives			13,118				(99,907	)
Net impact of natural gas inventory transactions			(1,558	)			10,552
Revenues from fee-based storage			11,299				8,342
Other costs			(1,265	)			(1,869	)
Total storage margin		$	8,476			$	17,025

Operating Expenses. Intrastate operating expenses primarily decreased between the periods due to a decrease in consumption expense of $7.8 million. Additionally, we experienced lower ad valorem expenses of $1.4 million, lower compressor maintenance expense of $1.2 million and lower electricity expense of $1.1 million as compared to the prior period.

Depreciation and Amortization. Intrastate transportation and storage depreciation and amortization expense increased primarily due to the completion of projects in connection with the continued expansion of our pipeline system.

Selling, General and Administrative. Intrastate selling, general and administrative expenses decreased between the periods as a result of a decrease in professional fees of $6.3 million offset by an increase in employee-related costs (including allocated overhead) of $2.4 million.

Interstate Transportation

 

		Three Months Ended March 31,
		2010			2009			Change
Natural gas MMBtu/d — transported			1,557,921			1,747,560			(189,639	)
Natural gas MMBtu/d — sold			20,043			15,044			4,999
Revenues		$	68,269		$	61,349		$	6,920
Operating expenses			16,061			15,365			696
Depreciation and amortization			12,451			10,659			1,792
Selling, general and administrative			8,160			7,130			1,030
Segment operating income		$	31,597		$	28,195		$	3,402

The interstate transportation segment data presented above does not include our interstate pipeline joint ventures, for which we reflect our proportionate share of income within “Equity in earnings of affiliates” below operating income in our condensed consolidated statement of operations. During the three months ended March 31, 2010, we recognized $5.5 million in equity in earnings primarily related to our 50% joint venture investment in MEP.

Volumes. Transported volumes decreased as compared to the prior period primarily as a result of less favorable market conditions for transporting natural gas principally from the San Juan Basin to East delivery points.

Revenues. Interstate transportation revenues increased between the periods by approximately $1.6 million as a result of the completion of the Phoenix project in February 2009 and a $5.3 million increase in operational sales revenues due to increases in natural gas prices and volume sold.

Operating Expenses. Operating expenses increased between the periods primarily due to an increase in ad valorem taxes resulting from increased property values related to the Phoenix pipeline expansion. This increase was partially offset by a net decrease in other operating expenses primarily due to lower electric demand costs resulting from lower throughput.

 

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Depreciation and Amortization. Depreciation and amortization expense increased between the periods primarily due to incremental depreciation associated with the completion of the Phoenix pipeline expansion.

Selling, General and Administrative. Selling, general and administrative expenses increased between the periods primarily due to increased administrative expense allocation offset by decreased employee-related costs.

Midstream

 

		Three Months Ended March 31,
		2010			2009			Change
Natural gas sold (MMBtu/d)			697,644			1,091,391			(393,747	)
NGLs produced (Bbls/d)			48,312			46,580			1,732
Revenues		$	796,771		$	631,632		$	165,139
Cost of products sold			699,792			559,176			140,616
Gross margin			96,979			72,456			24,523
Operating expenses			17,830			17,793			37
Depreciation and amortization			21,321			17,496			3,825
Selling, general and administrative			6,482			13,014			(6,532	)
Segment operating income		$	51,346		$	24,153		$	27,193

Volumes. NGL production increased between periods primarily due to increased inlet volumes at our Godley plant as a result of favorable NGL prices. The decrease in natural gas sold during the period primarily reflects decreased marketing activities resulting from less favorable market conditions.

The components of our midstream segment gross margin were as follows:

Gross Margin.

 

		Three Months Ended March 31,
		2010				2009			Change
Gathering and processing fee-based revenues		$	54,294			$	47,908		$	6,386
Non fee-based contracts and processing			47,271				17,207			30,064
Other			(4,586	)			7,341			(11,927	)
Total gross margin		$	96,979			$	72,456		$	24,523

Midstream gross margin increased primarily due to favorable NGL pricing. Our non fee-based processing agreements, which accounted for 46% of processed volumes during the three months ended March 31, 2010, benefited from higher NGL pricing. The composite NGL price increased to $1.09 per gallon from $0.60 per gallon in the prior period. The increase in NGL volumes that we received as fees for processing, as well as more favorable pricing, resulted in an increase in our non fee-based margin of $30.0 million. Total plant production also increased slightly in the period ended March 31, 2010. In addition, acquisitions and other growth capital expenditures located in Louisiana provided an increase in our fee-based margin of $6.4 million.

The decrease in other midstream gross margin reflects a decrease of $11.9 million from marketing activities due to less favorable market conditions compared to the prior year. We also recognized unrealized losses of $2.9 million for the three months ended March 31, 2010 compared to $11.2 million in the comparable period.

Operating Expenses. No significant changes occurred in midstream operating expenses compared to the prior period.

Depreciation and Amortization. Midstream depreciation and amortization expense increased between the periods primarily due to incremental depreciation from the continued expansion of our Louisiana assets.

Selling, General and Administrative. Midstream selling, general and administrative expenses decreased between the periods primarily due to a decrease in employee-related costs (including allocated overhead expenses) of approximately $4.4 million and a decrease in professional fees of $2.1 million.

 

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Retail Propane and Other Retail Propane Related

 

		Three Months Ended March 31,
		2010			2009			Change
Retail propane gallons (in thousands)			217,611			218,480			(869	)
Retail propane revenues		$	533,439		$	487,907		$	45,532
Other retail propane related revenues			27,716			28,005			(289	)
Retail propane cost of products sold			304,981			220,222			84,759
Other retail propane related cost of products sold			4,776			4,883			(107	)
Gross margin			251,398			290,807			(39,409	)
Operating expenses			91,732			94,176			(2,444	)
Depreciation and amortization			20,088			20,272			(184	)
Selling, general and administrative			12,804			12,290			514
Segment operating income		$	126,774		$	164,069		$	(37,295	)

Volumes. Despite continued effects of customer conservation and the impact of the economic recession, retail propane volumes decreased only slightly. Volumes were favorably impacted by weather which was approximately 5.3% colder than normal as compared to weather which was 2.4% colder than normal during the same period in 2009. We use information gathered on temperatures based on heating degree days from information published by the National Oceanic and Atmospheric Administration (“NOAA”) to also analyze how our volume sales are affected by temperature. Our normal temperatures are based on the average heating degree days provided by NOAA for various data points in our operating areas for the 10-year period ending March 2010. Based on this information we calculate a ratio of actual heating degree days to normal heating degree days.

Gross Margin. Revenues increased period over period due to increases in average wholesale propane commodity prices. In addition, to hedge a significant portion of our propane sales commitments entered into under our customer prebuy programs, we utilize financial instruments to lock in margins. Prior to April 2009, these financial instruments were not designated as cash flow hedges for accounting purposes, and changes in market value were recorded in cost of products sold in the condensed consolidated statements of operations. During the three month period ended March 31, 2009, our propane margins were positively impacted by the settlement of financial instruments related to sales commitments that were entered into in 2008. Having recognized unrealized losses of $45.6 million on these financial instruments during 2008, we recognized unrealized gains of $35.0 million during the period ended March 31, 2009 as the contracts settled in the period. In comparison, only $3.3 million of unrealized gains were recognized during 2009 and settled as unrealized losses during the period ended March 31, 2010. Excluding the impact of the mark-to-market accounting, gross margins were consistent period over period.

Operating Expenses. Operating expenses decreased primarily due to a decrease in our operational employee incentive program of $4.5 million which was partially offset by increases in vehicle fuel expenses of $1.4 million and increases in business insurance reserves and claims of $1.0 million.

Liquidity and Capital Resources

Parent Company Only

The Parent Company currently has no separate operating activities apart from those conducted by ETP and its Operating Companies. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner interests of ETP. The amount of cash that ETP can distribute to its partners, including the Parent Company, each quarter is based on earnings from ETP’s business activities and the amount of available cash, as discussed below. The Parent Company also has a $500.0 million revolving credit facility that expires in February 2011 with available capacity of $374.0 million as of March 31, 2010.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its general and limited partners. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP.

 

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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 our midstream and intrastate transportation and storage segments primarily for the construction of new pipelines and compression, for which we expect to spend between $180 million and $200 million for the remainder of 2010;

 

•

growth capital expenditures for our interstate transportation segment, excluding capital contributions to our joint ventures as discussed below, for the construction of new pipelines for which we expect to spend between $820 million and $890 million for the remainder of 2010;

 

•

growth capital expenditures for our retail propane segment of between $20 million and $30 million for the remainder of 2010; and

 

•

maintenance capital expenditures of between $70 million and $90 million for the remainder of 2010, which include (i) capital expenditures for our intrastate operations for pipeline integrity and for connecting additional wells to our intrastate natural gas systems in order to maintain or increase throughput on existing assets; (ii) capital expenditures for our interstate operations, primarily for pipeline integrity; and (iii) capital expenditures for our propane operations to extend the useful lives of our existing propane assets in order to sustain our operations, including vehicle replacements on our propane vehicle fleet.

In addition to the capital expenditures noted above, we expect that capital contributions on the joint ventures that we currently have interests in will be between $100 million and $120 million for the remainder of 2010.

In addition, we 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. In addition, ETP raised $81.0 million in net proceeds during the three months ended March 31, 2010 under an equity distribution program, as described in Note 12 to our condensed consolidated financial statements. As of March 31, 2010, in addition to approximately $384.3 million of cash on hand, ETP had available capacity under the ETP Credit Facility of approximately $1.94 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 2010; however, we 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.

Cash Flows

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

 

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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.

Three months ended March 31, 2010 compared to three months ended March 31, 2009. Cash provided by operating activities during 2010 was $475.0 million as compared to $413.0 million for 2009. Net income was $204.1 million and $279.8 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 $109.2 million and $75.9 million and changes in operating assets and liabilities of $161.7 million and $57.3 million for 2010 and 2009, respectively.

The non-cash activity in 2010 and 2009 consisted primarily of depreciation and amortization of $86.3 million and $75.7 million, respectively. In addition, non-cash compensation expense was $7.7 million and $7.3 million for 2010 and 2009, respectively. We also received distributions from our affiliates during 2010 that exceeded our equity in earnings by $10.1 million. These amounts are partially offset by the allowance for equity funds used during construction of $1.3 million and $20.4 million for 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 our joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

Three months ended March 31, 2010 compared to three months ended March 31, 2009. Cash used in investing activities during 2010 was $266.1 million as compared to $384.4 million for 2009. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2010 were $119.7 million, net of changes in accruals of $22.2 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2009 of $263.8 million, including changes in accruals of $71.3 million. In addition, in 2010 we paid cash for acquisitions of $149.6 million and made advances to our joint ventures of $0.1 million. We paid cash for acquisitions of $5.5 million and made advances to our joint ventures of $119.9 million ($111.0 million to MEP and $8.9 million to FEP) during 2009.

Growth capital expenditures for 2010, before changes in accruals, were $81.9 million for our midstream and intrastate transportation and storage segments, $30.5 million for our interstate transportation segment, and $9.9 million for our retail propane segment and all other. We also incurred $19.6 million of maintenance capital expenditures, of which $7.6 million related to our midstream and intrastate transportation and storage segments, $3.7 million related to our interstate segment and $8.3 million related to our retail propane segment and all other.

Growth capital expenditures for 2009, before changes in accruals, were $136.7 million for our midstream and intrastate transportation and storage segments, $28.9 million for our interstate transportation segment, and $12.3 million for our retail propane segment and all other. We also incurred $14.6 million in maintenance expenditures, of which $8.1 million related to our midstream and intrastate transportation and storage segments and $6.5 million related to our retail propane segment.

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 under “Financing and Sources of Liquidity,” which are primarily used to fund our 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.”

Three months ended March 31, 2010 compared to three months ended March 31, 2009. Cash provided by financing activities during 2010 was $107.2 million as compared to cash used in financing activities of $14.2 million for 2009. In 2010, we received $504.5 million in net proceeds from ETP Common Unit offerings, including $81.0 million under ETP’s equity distribution program, as compared to $225.9 million in 2009 (see Note 12 to our condensed consolidated financial statements). Net proceeds from the ETP offerings were used to repay outstanding borrowings under the ETP Credit Facility, to fund capital expenditures, to fund capital contributions to joint ventures, as well as for general

 

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partnership purposes. During 2010, we had a net decrease in our debt level of $162.1 million as compared to $38.6 million for 2009. We paid distributions of $120.8 million to our partners in 2010 as compared to $114.0 million in 2009. In addition, during 2010 and 2009, ETP paid distributions of $114.4 million and $87.2 million, respectively, of distributions on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.

Financing and Sources of Liquidity

In January 2010, ETP issued 9,775,000 Common Units through a public offering. The proceeds of $423.6 million from the offering were used primarily to repay borrowings under ETP’s revolving 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 three months ended March 31, 2010, ETP issued 1,760,783 of ETP Common Units pursuant to this agreement. In addition, ETP initiated trades on 326,633 ETP Common Units that had not settled as of March 31, 2010. The proceeds of approximately $81.0 million, net of commissions, were used for general partnership purposes. Approximately $134.8 million remains available to be issued under the agreement as of March 31, 2010.

Description of Indebtedness

Our outstanding indebtedness was as follows:

 

		March 31, 2010				December 31, 2009
Parent Company Indebtedness:
Senior Secured Term Loan Facility		$	1,450,000			$	1,450,000
Senior Secured Revolving Credit Facility			126,006				123,951
Subsidiary Indebtedness:
ETP Senior Notes			5,050,000				5,050,000
Transwestern Senior Unsecured Notes			870,000				870,000
HOLP Senior Secured Notes			140,512				140,512
Revolving credit facilities			—				160,000
Other long-term debt			9,503				10,288
Unamortized discounts			(12,645	)			(12,829	)
Fair value adjustments related to interest rate swaps			(1,453	)			—
Total debt		$	7,631,923			$	7,791,922

The terms of our indebtedness and that of our Operating Companies 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

The Parent Company has a $1.45 billion Term Loan Facility with a Term Loan Maturity Date of November 1, 2012 (the “Parent Company Credit Agreement”). The Parent Company Credit Agreement also includes a $500.0 million Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of March 31, 2010 was $1.58 billion. The total amount available under the Parent Company’s debt facilities as of March 31, 2010 was $374.0 million. The Parent Company Revolving Credit Facility also contains an accordion feature, which will allow the Parent Company, subject to lender approval, to expand the facility’s capacity up to an additional $100.0 million.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio, which is currently at Level I or 0.3%. Loans under the Parent Company

 

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Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set-forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. At March 31, 2010, the weighted average interest rate was 1.94% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $1.45 billion Senior Secured Term Loan Facility.

ETP 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 Amended and Restated Credit Agreement). 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 a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating and the fee is 0.11% based on our current rating with a maximum fee of 0.125%.

As of March 31, 2010, there was no balance outstanding on the ETP Credit Facility, and taking into account letters of credit of approximately $62.2 million, $1.94 billion was available for future borrowings.

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 a 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 March 31, 2010, there was no outstanding balance in revolving credit loans and outstanding letters of credit of $1.0 million. The amount available for borrowing as of March 31, 2010 was $74.0 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. Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if our ownership percentage 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 a 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.

The commitment amount under the MEP Facility was $255.4 million as of March 31, 2010 and it had $89.0 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 $44.5 million and $16.6 million, respectively, as of March 31, 2010. The weighted average interest rate on the total amount outstanding as of March 31, 2010 was 1.5%. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions.

 

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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”). We have 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, our guarantee may be proportionately increased or decreased if our ownership percentage 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 a 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%.

As of March 31, 2010, FEP had $468.0 million of outstanding borrowings issued under the FEP Facility. Our contingent obligation with respect to our 50% guarantee of FEP’s outstanding borrowings was $234.0 million as of March 31, 2010. The weighted average interest rate on the total amount outstanding as of March 31, 2010 was 3.2%.

Debt Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements at March 31, 2010.

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.

On February 19, 2010, the Parent Company paid a cash distribution for the three months ended December 31, 2009 of $0.54 per Common Unit, or $2.16 annualized, to Unitholders of record at the close of business on February 8, 2010.

On April 27, 2010, the Parent Company announced the declaration of a cash distribution for the three months ended March 31, 2010 of $0.54 per Common Unit, or $2.16 annualized. This distribution will be paid on May 17, 2010 to Unitholders of record at the close of business on May 7, 2010.

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

 

		Three Months Ended March 31,
		2010			2009
Limited Partners		$	120,388		$	117,021
General Partner			374			363
Total distributions declared		$	120,762		$	117,384

Cash Distributions Received by the Parent Company

Currently, the Parent Company’s only cash-generating assets are its direct and indirect partnership interests in ETP. These ETP interests consist of all of ETP’s general partner interest, 100% of ETP’s incentive distribution rights and ETP Common Units held by the Parent Company.

 

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The total amount of distributions the Parent Company received from ETP 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:

 

		Three Months Ended March 31,
		2010			2009
Limited Partners		$	55,860		$	55,860
General Partner Interest			4,880			4,860
Incentive Distribution Rights			94,917			84,146
Total distributions received from ETP		$	155,657		$	144,866

Cash Distributions Paid by ETP

ETP expects to use substantially all of its cash provided by operating and financing activities from the Operating Companies to provide distributions to its Unitholders. Under ETP’s partnership agreement, ETP will distribute to its partners within 45 days after the end of each calendar quarter, an amount equal to all of its Available Cash (as defined in ETP’s partnership agreement) for such quarter. Available Cash generally means, with respect to any quarter of ETP, all cash on hand at the end of such quarter less the amount of cash reserves established by ETP’s General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. ETP’s commitment to its Unitholders is to distribute the increase in its cash flow while maintaining prudent reserves for its operations.

On February 15, 2010, ETP paid a cash distribution for the three months ended December 31, 2009 of $0.89375 per Common Unit, or $3.575 annualized to Unitholders of record at the close of business on February 8, 2010.

On April 27, 2010, ETP declared a cash distribution for the three months ended March 31, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on May 17, 2010 to Unitholders of record at the close of business on May 7, 2010.

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

 

		Three Months Ended March 31,
		2010			2009
Limited Partners:
Common Units		$	170,921		$	150,853
Class E Units			3,121			3,121
General Partner Interest			4,880			4,860
Incentive Distribution Rights			94,917			84,146
Total distributions declared by ETP		$	273,839		$	242,980

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.

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. Since December 31, 2009, there have been no material changes to our primary market risk exposures or how those exposures are managed.

 

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Commodity Price Risk

The table below summarizes our commodity-related financial derivative instruments and fair values as of March 31, 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 and gallons for propane/ethane. Dollar amounts are presented in thousands.

 

		March 31, 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		47,882,500			$	18,215			$	63		72,325,000			$	24,554			$	491
Swing Swaps IFERC		(6,465,000	)			2,069				3,110		(38,935,000	)			1,718				2,142
Fixed Swaps/Futures		(14,775,000	)			1,642				6,517		4,852,500				9,949				3,126
Options — Puts		(15,870,000	)			15,779				582		2,640,000				837				447
Options — Calls		(22,580,000	)			(9,253	)			153		(2,640,000	)			(819	)			314
Propane/Ethane:
Forwards/Swaps		42,000				16				5		6,090,000				3,348				785
Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX		(3,602,500	)			72				6		(22,625,000	)			(4,178	)			2
Fixed Swaps/Futures		(6,865,000	)			3,089				2,890		(27,300,000	)			(13,285	)			15,669
Cash Flow Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX		(9,625,000	)			(1,525	)			30		(13,225,000	)			(1,640	)			81
Fixed Swaps/Futures		(16,500,000	)			23,841				7,042		(22,800,000	)			(4,464	)			13,197
Options — Puts		22,200,000				3,872				4,556		—				—				—
Options — Calls		(22,200,000	)			3,902				2,176		—				—				—
Propane/Ethane:
Forwards/Swaps		6,636,000				731				740		20,538,000				8,443				2,609

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 our condensed consolidated results of operations 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.

Interest Rate Risk

As of March 31, 2010, ETE had $1.58 billion of variable rate debt outstanding, of which $1.5 billion was swapped to a fixed rate using interest rate derivatives. Of the total notional amount of $1.5 billion of interest rate derivatives, $800 million are accounted for as non-hedged interest rate derivatives (of which $500 million of notional amount may be cancelled at the option of the counterparty in November 2010). Changes in the fair value of non-hedged interest rate derivatives, along with cash settlements related to those derivatives, are reported in "Gains (losses) on non-hedged interest rate derivatives" in the statements of operations. The remaining $700 million of notional amount of interest rate derivatives at ETE are accounted for as cash flow hedges of forecasted interest payments. ETP had no variable rate debt

 

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outstanding as of March 31, 2010, but it had $1.1 billion of its fixed rate debt swapped to a variable rate using interest rate derivatives. ETP's interest rate derivatives are accounted for under hedge accounting as fair value hedges of the fixed rate debt.

A hypothetical change of 100 basis points in interest rates would result in a change to consolidated interest expense of approximately $19.8 million annually. A hypothetical change of 100 basis points in interest rates also would result in a net change in the fair value of interest rate derivatives of approximately $3.4 million, of which approximately $30.6 million would be immediately recognized in income as a gain or loss on non-hedged interest rate derivatives. The remaining change in the fair value of interest rate derivatives would not have an immediate impact to income based on the application of hedge accounting.

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 consolidated balance sheet and recognized in net income or other comprehensive income.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the President (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of March 31, 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 and Principal Financial Officers of our General Partner, to allow timely decisions regarding required disclosure.

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 March 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

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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 14 — Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Condensed Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Form 10-Q for the quarter ended March 31, 2010.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2009.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 5. OTHER INFORMATION

Deferred Compensation Plan

Effective January 1, 2010, we adopted the Energy Transfer Partners Deferred Compensation Plan (the “Plan”) as a participating employer. This voluntary, nonqualified Plan allows a select group of management and highly-compensated employees to elect to defer receipt of certain compensation. Each of ETP’s and ETE’s named executive officers is eligible to participate in the Plan; however, since 2007, Mr. Warren has voluntarily elected not to accept any salary, bonus, or equity incentive compensation and thus will not participate in the Plan. Participants may elect to defer up to 50% of their base salary, cash bonus and/or cash distributions paid with respect to unvested unit-based awards granted under ETP’s 2008 Long-Term Incentive Plan and the Partnership’s long-term incentive plan (the “Deferred Amounts”) and may choose from various investment options in which the Deferred Amounts are notionally invested. The Plan is funded by a grantor trust, but Plan assets remain subject to the claims of our general creditors. The Deferred Amounts and any related investment earnings are payable (in a lump sum and/or installments) upon the termination of a participant’s employment for any reason, a change in control, a specified date, and/or death, as specified by the participant. If a participant terminates or dies prior to the elected distribution date, his benefits will be paid upon termination in the form previously elected or, if applicable, upon death as a lump sum. A participant may also receive a distribution in the case of specified financial hardships, with the consent of the Plan’s administrative committee. The Plan is intended to comply with section 409A of the Internal Revenue Code of 1986, as amended.

A copy of the Plan is attached as Exhibit 10.1 hereto and incorporated herein by reference. The foregoing summary of certain provisions of the Plan is qualified in its entirety by reference to such Plan document.

 

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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
3.1		333-128097		3.1		Certificate of Conversion of Energy Transfer Company, L.P.
3.2		333-128097		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.
3.4		333-128097		3.4		Certificate of Conversion of LE GP, LLC.
3.5		333-128097		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		3.2		Agreement of Limited Partnership of Heritage Operating, L.P.
3.8.1		1-11727 (10-K) (8/31/00)		3.2.1		Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
3.8.2		1-11727 (10-Q) (5/31/02)		3.2.2		Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
3.8.3		1-11727 (10-Q) (2/29/04)		3.2.3		Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
3.9		1-11727 (10-Q) (2/29/04)		3.3		Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.
3.10		1-11727 (10-Q) (2/28/02)		3.4		Amended Certificate of Limited Partnership of Heritage Operating, L.P.
3.11		1-11727 (10-Q) (5/31/07)		3.5		Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P.
3.12		1-11727 (10-Q) (5/31/07)		3.6		Third Amended and Restated Limited Liability Agreement of Energy Transfer Partners, L.L.C.
3.13		333-128097		3.13		Certificate of Formation of Energy Transfer Partners, L.L.C.
3.13.1		333-128097		3.13.1		Certificate of Amendment of Energy Transfer Partners, L.L.C.
3.14		333-128097		3.14		Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P.
10.1						Energy Transfer Partners Deferred Compensation Plan.

 

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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.

 

*	Incorporated herein by reference.

 

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SIGNATURE

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

ENERGY TRANSFER EQUITY, L.P.

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

Date: May 7, 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 10.1

Energy Transfer Partners Deferred Compensation Plan

ARTICLE I

PURPOSE AND EFFECTIVE DATE

The purpose of the Energy Transfer Partners Deferred Compensation Plan (“Plan”) is to aid the Company and its Affiliates in retaining and attracting executive employees by providing them with tax deferred savings opportunities. This voluntary nonqualified Plan provides a select group of management and highly compensated employees, within the meaning of ERISA Sections 201(2), 301(a)(3) and 401(a)(1), with the opportunity to elect to defer receipt of specified portions of compensation, and to have these deferred amounts treated as if invested in specified hypothetical investment benchmarks. The Plan is intended to conform to the requirements of Code Section 409A. The Plan shall be effective January 1, 2010, and deferral elections made hereunder shall be effective, with respect to Base Salary Deferrals, on or after the first day of the first payroll period of the Company and its Affiliates that begins on or after January 1, 2010 and, with respect to all other Deferred Amounts, on or after January 1, 2010.

ARTICLE II

DEFINITIONS

For the purposes of this Plan, the following words and phrases shall have the meanings indicated, unless the context clearly indicates otherwise:

Section 2.01 Account. “Account” or “Accounts” means the fair market value of Deferred Amounts and Earnings thereon as established under the terms of the Plan and reflected in the bookkeeping accounts maintained by the Employer from time to time. As used in context, “Account” may refer to the Participant’s entire interest under the Plan or, if used in the context of a specific plan year (e.g. “2010 Account” or “Plan Year Account”) may refer to the portion of the Participant’s interest under the Plan that reflect the Deferred Amount and Earnings thereon only for a Plan Year, or, if used in the context of a specific type of Deferred Amounts (e.g., “Plan Year Base Salary Account” or “Plan Year Discretionary Contribution Account”) those types of Deferred Amounts and Earnings thereon.

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Section 2.02 Administrative Committee. “Administrative Committee” means the committee appointed by the Board to administer the Plan.

Section 2.03 Affiliate. “Affiliate” means each trade or business (whether or not incorporated) which together with the Company would be deemed to be a “single employer” within the meaning of subsections (b) or (c) of Code Section 414, in each case determined by a 50% control test.

Section 2.04 Base Salary. “Base Salary” means the base rate of cash compensation paid by the Employer to or for the benefit of a Participant for services rendered or labor performed while a Participant, including the portion thereof that a Participant could have received in cash in lieu of (i) Base Salary Deferrals pursuant to Section 4.02 and (ii) elective contributions made on his behalf by the Employer pursuant to a qualified cash or deferred arrangement (as defined in Code Section 401(k)) or pursuant to a plan maintained under Code Section 125.

Section 2.05 Base Salary Deferral. “Base Salary Deferral” means the amount of a Participant’s Base Salary that the Participant elects to defer under the Plan for a Plan Year and that is credited to his or her Account pursuant to Section 5.01.

Section 2.06 Beneficiary. “Beneficiary” means the person, persons or entity designated by the Participant pursuant to Article VIII to receive any benefits payable under the Plan in the event of the Participant’s death.

Section 2.07 Benefit Commencement Date. “Benefit Commencement Date” means the date specified in a Deferral Agreement upon which payment of an Account is to be made or commence.

Section 2.08 Board. “Board” means the Board of Directors of the Company.

Section 2.09 Change of Control. For purposes of this Plan, a “Change of Control” means any “change in control event” within the meaning of Treasury Regulation Section 1.409A-3(i)(5).

Section 2.10 Code. “Code” shall mean the Internal Revenue Code of 1986, as amended, including regulations and guidance of general applicability issued thereunder.

Section 2.11 Company. “Company” means Energy Transfer Partners GP, L.P. and its successors.

Section 2.12 Deferral Agreement. “Deferral Agreement” means an agreement filed by a Participant in accordance with Article IV.

Section 2.13 Deferred Amount. “Deferred Amount” means a Participant’s Base Salary Deferrals, Incentive Compensation Deferrals and Unit Distributions Deferrals and Discretionary Contributions made on the Participant’s behalf, if any.

Section 2.14 Designee. “Designee” shall mean the Employer’s senior human resources officers or other individuals to whom the Administrative Committee has delegated its authority to act under the Plan. Wherever Administrative Committee is referenced in the plan, it shall be deemed to also refer to Designee.

 

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Section 2.15 Discretionary Contribution. “Discretionary Contribution,” if any, means the amount of any discretionary employer contribution, including any matching contribution that the Employer agrees to make to the Plan from time to time.

Section 2.16 Earnings. “Earnings” shall mean the earnings credited to and/or losses debited from a Participant’s Account on the basis of the Hypothetical Investment Benchmarks applicable to the Participant’s Account under Section 5.02.

Section 2.17 Eligible Compensation. “Eligible Compensation” means any Base Salary, Incentive Compensation, and Unit Distributions that are earned for services performed during a Plan Year or performance period, as applicable. Eligible Compensation does not include expense reimbursements, any form of noncash compensation or transfer of property, or compensation, whether cash or noncash, paid under a stock- or unit-based plan other than Unit Distributions.

Section 2.18 Employer. “Employer” means the Company and any Affiliate designated by the Board or the Administrative Committee to participate in the Plan pursuant to Section 10.02.

Section 2.19 ERISA. “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

Section 2.20 Form of Payment. “Form of Payment” means either a single sum distribution or substantially equal annual installments over a period of either 3 years or 5 years (as specified under Article IV). If the Form of Payment is substantially equal annual installments, the installments will be treated as a single payment for purposes of Code Section 409A.

Section 2.21 Hardship Withdrawal. “Hardship Withdrawal” means a payment on account of an unforeseeable emergency, as defined in Code Section 409A(a)(2)(B)(ii), pursuant to Section 6.05.

Section 2.22 Hypothetical Investment Benchmark. “Hypothetical Investment Benchmark” means the phantom investment benchmarks that are used to measure the earnings credited to and/or losses debited from a Participant’s Account.

Section 2.23 Incentive Compensation. “Incentive Compensation” means any cash incentive bonuses paid by the Employer to or for the benefit of a Participant for services rendered or labor performed while a Participant, including the portion thereof that a Participant could have received in cash in lieu of (i) Incentive Compensation deferrals pursuant to Section 4.02 and (ii) elective contributions made on his behalf by the Employer pursuant to a qualified cash or deferred arrangement (as defined in Code Section 401(k)) or pursuant to a plan maintained under Code Section 125 of the Code, but excluding Unit Distributions and any cash incentive bonuses earned by the Participant over a performance period of longer than 12 months (except any Performance Bonuses permitted to be deferred under Section 4.02(f)). For the avoidance of doubt, “Incentive Compensation” shall not include any compensation paid under a stock- or unit-based plan nor shall it include any cash incentive bonuses earned over a multi-year service period unless such bonuses are Performance Bonuses for which the Administrative Committee has permitted a deferral election in accordance with Section 4.02(f).

 

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Section 2.24 Incentive Compensation Deferral. “Incentive Compensation Deferral” means the amount of a Participant’s Incentive Compensation that the Participant elects to defer under the Plan for a Plan Year and that is credited to his Account pursuant to Section 5.01.

Section 2.25 Modification Agreement. “Modification Agreement” means the form filed by a Participant to change the Benefit Commencement Date or the Form of Payment with respect to an Account under rules established by the Administrative Committee from time to time and pursuant to Section 4.03(b).

Section 2.26 Participant. “Participant” means any individual who (a) is eligible to participate in this Plan pursuant to Section 4.01 and (b) who elects to participate by filing a Deferral Agreement pursuant to Section 4.02 or for whom the Employer has made a Discretionary Contribution to the Plan.

Section 2.27 Performance Bonus. “Performance Bonus” means a cash incentive bonus that constitutes “performance-based compensation” within the meaning of Code Section 409A(a)(B)(iii).

Section 2.28 Plan Year. “Plan Year” means a twelve-month period beginning January 1 and ending the following December 31.

Section 2.29 Separation from Service. “Separation from Service” means the termination of a Participant’s employment with the Employer and all Affiliates for any reason whatsoever. A Participant shall be considered to have terminated his employment if it is reasonably anticipated that the bona fide level of services he would perform after a certain date (whether performed as an employee or independent contractor) would permanently decrease to no more than 20 percent of the average rate of services performed prior to such reduction over the immediately preceding 36-month period (or the full period of services to the Employer, if the employee has been providing services to the Employer for less than 36 months). If a Participant ceases or reduces services under a bona fide leave of absence, a Separation from Service occurs after the close of the 6-month anniversary of such leave, provided however that the Separation from Service shall be delayed to the extent that the employee has a statutory or contractual right to reemployment. Determination of whether a Separation from Service occurs shall be made in accordance with Treasury Regulation Section 1.409A-1(h). “Separate from Service” shall also be used herein to refer to a Separation from Service as defined above, as the context requires.

Section 2.30 Trust. “Trust” means the irrevocable grantor trust established under the Trust Agreement.

Section 2.31 Trust Agreement. “Trust Agreement” means the agreement entered into between the Employer and the Trustee pursuant to Article IX.

Section 2.32 Trust Fund. “Trust Fund” means the funds and properties held pursuant to the provisions of the Trust Agreement, together with all income, profits and increments thereto.

Section 2.33 Trustee. “Trustee” means the independent commercial trustee or trustees qualified and acting under the Trust Agreement at any time.

 

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Section 2.34 Unit Distributions. “Unit Distributions” means cash distributions made by the Employer to or for the benefit of a Participant with respect to outstanding unvested unit-based awards granted pursuant to the Company’s long-term incentive plan for services rendered or labor performed while a Participant, including the portion thereof that a Participant could have received in cash in lieu of (i) Unit Distributions Deferrals pursuant to Section 4.02 and (ii) elective contributions made on his behalf by the Employer pursuant to a qualified cash or deferred arrangement (as defined in Code Section 401(k)) or pursuant to a plan maintained under Code Section 125, but only if the right to receive and retain such cash distributions is not subject to any vesting requirements other than a requirement that the recipient be employed on the date of payment.

Section 2.35 Unit Distributions Deferral. “Unit Distributions Deferral” means the amount of a Participant’s Unit Distributions that the Participant elects to defer under the Plan for a Plan Year and that is credited to his Account pursuant to Section 5.01.

Section 2.36 Valuation Date. “Valuation Date” means each day the New York Stock Exchange is open for business, or such other date as the Administrative Committee in its sole discretion may determine.

ARTICLE III

ADMINISTRATION

Section 3.01 Administrative Committee Duties. This Plan shall be administered by the Administrative Committee. A majority of the members of the Administrative Committee shall constitute a quorum for the transaction of business. All resolutions or other action taken by the Administrative Committee shall be by a vote of a majority of its members present at any meeting or, without a meeting, by an instrument in writing signed by all its members. Members of the Administrative Committee may participate in a meeting of such committee by means of a conference telephone or similar communications equipment that enables all persons participating in the meeting to hear each other, and such participation in a meeting shall constitute presence in person at the meeting and waiver of notice of such meeting.

The Administrative Committee shall be responsible for the administration of this Plan and shall have all powers necessary to administer this Plan, including discretionary authority to determine eligibility for benefits, to decide claims under the terms of this Plan, and to determine issues related to eligibility, Hypothetical Investment Benchmarks, distribution of Accounts, determination of Account balances, crediting of hypothetical earnings and contributions and debiting of hypothetical losses and of distributions, in-service withdrawals, deferral elections and any other duties concerning the day-to-day operation of this Plan. The Administrative Committee may designate one of its members as a chairperson and may retain and supervise outside providers, third party administrators, recordkeepers and professionals (including in-house professionals) to perform any or all of the duties delegated to it hereunder.

The Administrative Committee may from time to time establish rules for the administration of this Plan, and it shall have the exclusive right to interpret this Plan and to decide any matters arising in connection with the administration and operation of this Plan. All rules, interpretations and decisions of the Administrative Committee shall be conclusive and binding on the Employer, Participants and Beneficiaries.

 

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No member of the Board or the Administrative Committee shall be liable for any act or action hereunder, whether of omission or commission, by any other member or employee or by any agent to whom duties in connection with the administration of this Plan have been delegated or for anything done or omitted to be done in connection with this Plan. The Administrative Committee shall keep records of all of its proceedings and shall keep records of all payments made to Participants or Beneficiaries and payments made for expenses or otherwise.

The Employer shall, to the fullest extent permitted by law, indemnify each director, officer or employee of the Employer (including the heirs, executors, administrators and other personal representatives of such person) and each member of the Administrative Committee against expenses (including attorneys’ fees), judgments, fines, amounts paid in settlement, actually and reasonably incurred by such person in connection with any threatened, pending or actual suit, action or proceeding (whether civil, criminal, administrative or investigative in nature or otherwise) in which such person may be involved by reason of the fact that he or she is or was serving this Plan in any capacity at the request of the Employer or the Administrative Committee. Expenses and liabilities arising out of gross negligence and willful misconduct shall not be covered by this indemnity.

Any expense incurred by the Employer or the Administrative Committee relative to the administration of this Plan shall be paid by the Employer and/or may be deducted from the Accounts of the Participants as determined by the Administrative Committee.

Section 3.02 Claims Procedures. If a Participant or Beneficiary (a “Claimant”) makes a written request alleging a right to receive payments under this Plan or alleging a right to receive an adjustment in benefits being paid under this Plan, such actions shall be treated as a claim for benefits. All claims for benefits under this Plan shall be sent to the Administrative Committee and administered in compliance with Section 409A. If the Administrative Committee determines that any individual who has claimed a right to receive benefits, or different benefits, under this Plan is not entitled to receive all or any part of the benefits claimed, the Administrative Committee shall inform the claimant in writing of such determination and the reasons therefor in terms calculated to be understood by the claimant. The notice shall be sent within 90 days of the claim unless the Administrative Committee determines that additional time, not exceeding 90 days, is needed and so notifies the Claimant. The notice shall make specific reference to the pertinent Plan provisions on which the denial is based, and shall describe any additional material or information that is necessary. Such notice shall, in addition, inform the claimant of the procedure that the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. The Claimant may within 60 days thereafter submit in writing to the Administrative Committee a notice that the claimant contests the denial of his or her claim and desires a further review by the Administrative Committee. The Administrative Committee shall within 60 days thereafter review the claim and authorize the claimant to review pertinent documents and submit issues and comments relating to the claim to the Administrative Committee. The Administrative Committee will render a final decision on behalf of the Company with specific reasons therefor in writing and will transmit it to the claimant within 60 days of the written request for review, unless the Administrative Committee determines that additional time, not exceeding 60 days, is needed, and so notifies the Participant. If the Administrative Committee fails to respond to a claim filed in accordance with the foregoing within 60 days or any extended period, the Company shall be deemed to have denied the claim.

 

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Completion of the claims procedures described in this Section 3.02 will be a condition precedent to the commencement of any legal or equitable action in connection with a claim for benefits under the Plan by a Claimant or by any other person or entity claiming rights individually or through a Claimant; provided, however, that the Administrative Committee may, in its sole discretion, waive compliance with such claims procedures as a condition precedent to any such action.

An authorized representative may act on behalf of a Claimant in pursuing a benefit claim or an appeal of an Adverse Benefit Determination. An individual or entity will only be determined to be a Claimant’s authorized representative for such purposes if the Claimant has provided the Administrative Committee with a written statement identifying such individual or entity as his authorized representative and describing the scope of the authority of such authorized representative. In the event a Claimant identifies an individual or entity as his authorized representative in writing to the Administrative Committee but fails to describe the scope of the authority of such authorized representative, the Administrative Committee shall assume that such authorized representative has full powers to act with respect to all matters pertaining to the Claimant’s benefit claim under the Plan or appeal of an Adverse Benefit Determination with respect to such benefit claim.

ARTICLE IV

PARTICIPATION, DEFERRAL AGREEMENTS, AND DISCRETIONARY CONTRIBUTIONS

Section 4.01 Participation.

(a) The President of the Company, in his sole discretion, shall select and notify those management or highly compensated employees of the Employer who shall be eligible to become a Participant in the Plan, and such employees may become Participants, effective as of the first day of the next Plan Year following such notification of eligibility, by executing and filing with the Administrative Committee a Deferral Agreement pursuant to Section 4.02. Any employee selected by the President of the Company as eligible to participate in the Plan in accordance with this Section 4.01 may also become a Participant without executing and filing a Deferral Agreement upon the crediting by the Employer of Discretionary Contributions to such Participant’s Account.

(b) Subject to Section 4.01(c), an employee who is eligible to participate in the Plan under Section 4.01(a) shall remain eligible to participate in the Plan for each Plan Year following his initial eligibility until his Separation from Service.

(c) Notwithstanding any provision herein to the contrary, an individual who has become a Participant of the Plan shall cease to be entitled to defer Eligible Compensation hereunder and/or receive an allocation of Discretionary Contributions effective as of the last day of any Plan Year designated by the Administrative Committee. Any such Administrative Committee action shall be communicated to the affected individual prior to the effective date of such action. Such an individual may again become entitled to defer Eligible Compensation hereunder and receive an allocation of Discretionary Contributions beginning as of the first day of any subsequent Plan Year selected by the Administrative Committee in its sole discretion.

 

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Section 4.02 Contents and Timing of Deferral Agreements.

(a) The Administrative Committee shall have the discretion to specify the contents of a Deferral Agreement and to establish deadlines regarding the filing of the Deferral Agreements, subject to the terms of the Plan.

(b) A Deferral Agreement must specify (i) the Base Salary Deferrals elected for the Plan Year, provided that the Base Salary Deferrals may not exceed 50% of the Participant’s Base Salary; (ii) the Incentive Compensation Deferrals elected for the Plan Year, provided that the Incentive Compensation Deferrals may not exceed 50% of the Participant’s Incentive Compensation; (iii) the Unit Distributions Deferrals elected for the Plan Year, provided that the Unit Distributions Deferrals may not exceed 50% of the Participant’s Unit Distributions; (iv) the Benefit Commencement Date; and (iv) the Form of Payment. Items (i), (ii), and (iii) above may be expressed as either a dollar amount or as a percentage, as prescribed by the Administrative Committee. If no Benefit Commencement Date is specified, the Deferral Agreement shall be deemed to specify a Benefit Commencement Date that is the date upon which the Participant Separates from Service. If no Form of Payment is specified, the Deferral Agreement shall be deemed to specify a Form of Payment that is a single lump sum.

(c) The Administrative Committee may, in its discretion, permit Deferral Agreements to specify a unique Benefit Commencement Date and Form of Payment with respect to different Plan Accounts for each Plan Year.

(d) Subject to Sections 4.02(i) and 6.05, Deferral Agreements shall be filed and become irrevocable with respect to Eligible Compensation no later than the December 31 preceding the Plan Year during which the services for such Eligible Compensation are first performed; provided, however, that in the event the Participant makes a hardship withdrawal under a 401(k) savings plan maintained by the Employer, his Deferral Agreement then in effect, if any, shall immediately terminate.

(e) Notwithstanding Section 4.02(d), the Administrative Committee may establish a later deadline for the filing and irrevocability of Deferral Agreements to the extent that the Administrative Committee determines that such deadlines conform to the requirements of Code Section 409A, including a deadline of no later than 30 days of initial eligibility for an employee who becomes newly eligible to participate in the Plan (such as a new hire to the Employer or in connection with the initial adoption of the Plan).

(f) Notwithstanding anything to the contrary in this Section 4.02, if permitted in accordance with the administrative procedures implemented by the Administrative Committee (which may vary among individual Participants), a Participant may elect to defer (or change an election to defer) a Performance Bonus after the start of a Plan Year or Plan Years in which such Performance Bonus is earned in whole or in part, provided that (i) such Participant executes and files with the Administrative Committee a Deferral Agreement with respect to such Performance Bonus in accordance with the procedures prescribed by the Administrative Committee no later than the date that is six months before the end of the performance period applicable thereto, (ii) such Participant has performed services continuously for the Employer from the later of the beginning of the

 

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performance period or the date upon which the performance criteria applicable to such Performance Bonus are established through a date no earlier than the date upon which the Participant makes an initial deferral election with respect thereto pursuant to this Section 4.02(f), and (iii) such Participant makes such election before the Performance Bonus has become readily ascertainable (within the meaning of Code Section 409A). In the event that such Participant has elected to defer Incentive Compensation for a Plan Year, any election by such Participant to defer a Performance Bonus under this Section 4.02(f) shall be deemed to override any election as to such Performance Bonus under Section 4.02(b)(ii), but only with respect to such Performance Bonus. In the event that a Participant is eligible to receive a Performance Bonus but has not made (or been offered) a special election to defer such Performance Bonus, any election made pursuant to Section 4.02(b)(ii) with respect to the Plan Year during which such Performance Bonus was earned shall apply to such Performance Bonus whenever it is paid.

(g) A Deferral Agreement shall become effective (1) with respect to Base Salary Deferrals, as of the first day of the first full payroll period that begins during the Plan Year that is immediately after the date the Deferral Agreement is effected by the Participant and filed with the Administrative Committee and (2) with respect to all other Deferred Amounts (except for deferrals of Performance Bonuses permitted pursuant Section 4.02(f)), as of the first day of the Plan Year that is immediately after the date the Deferral Agreement is effected by the Participant and filed with the Administrative Committee. Notwithstanding the foregoing, a Deferral Agreement filed after the deadline set forth in Section 4.02(d) pursuant to Section 4.02(e) above shall (A) become effective with respect to deferrals of the Participant’s Base Salary as of the first day of the first full payroll period that begins during the first calendar quarter commencing on or after the date the Participant was first notified of his Plan eligibility or, if he timely files his Deferral Agreement after the first day of such payroll period, such later date as may be administratively feasible after such Deferral Agreement is filed and shall be effective only with respect to Base Salary earned on or after the first day of the first payroll period of such first calendar quarter and after the filing of such Deferral Agreement, (B) become effective as soon as administratively feasible with respect to deferrals of the Participant’s Incentive Compensation for the Plan Year that is earned over a performance period that coincides with the Plan Year or the Participant’s term of employment during such Plan Year, if less (“Annual Incentive Compensation”), but shall apply only to a portion of the Participant’s Annual Incentive Compensation for the Plan Year equal to the total amount of the Participant’s Annual Incentive Compensation for the Plan Year multiplied by the ratio of the number of days remaining in the Plan Year after the effective date of the Deferral Agreement over the total number of days in the Plan Year during which the Participant was employed by the Employer, (C) become effective with respect to Incentive Compensation other than Annual Incentive Compensation at the start of the first performance period that coincides with or begins after the date that the Participant first defers Base Salary under the Plan, and (D) become effective with respect to deferrals of the Participant’s Unit Distributions at the start of the first performance period that coincides with or begins after the first day of the first calendar quarter commencing after the date the Participant timely files his Deferral Agreement.

(h) The reduction in a Participant’s Eligible Compensation pursuant to his Deferral Agreement shall be effected by Eligible Compensation reductions each payroll period as determined by the Administrative Committee following the effective date of the Deferral Agreement. Subject to Section 4.02(g), such Eligible Compensation reductions shall apply with respect to all Eligible Compensation earned while the Deferral

 

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Agreement is effective (as described in Sections 4.02(g) and (j)) regardless of when the Eligible Compensation is actually paid. For the sake of clarity, Eligible Compensation reductions attributable to elections to defer a Participant’s Incentive Compensation shall be made within the next following Plan Year if the Incentive Compensation to which the Participant’s Deferral Agreement relates is paid in such next following Plan Year.

(i) Any Plan provisions notwithstanding, deferrals pursuant to a Participant’s Deferral Agreement shall be suspended during any period of unpaid leave of absence from the Employer and shall terminate immediately on the date such Participant incurs a Separation from Service, except with respect to Eligible Compensation earned prior to that date.

(j) A Deferral Agreement for a Plan Year shall no longer be effective (1) with respect to Base Salary Deferrals, as of the first day of the first full payroll period that begins during the subsequent Plan Year and (2) with respect to all other Deferred Amounts, as of the first day of the subsequent Plan Year, except with respect to Compensation earned but not paid prior to such dates, as applicable. A Participant may file a new Deferral Agreement for a subsequent Plan Year if he satisfies the eligibility requirements set forth in Section 4.01, provided that the new Deferral Agreement is executed and filed prior to the deadlines set forth in Sections 4.02(d), (e), or (f), as applicable, and within the time period prescribed by the Administrative Committee.

Section 4.03 Modification or Revocation of Election by Participant.

(a) A Participant may not change the amount of Eligible Compensation to be deferred for a Plan Year after the date on which such election is irrevocable pursuant to Section 4.02(d), (e), or (f), as applicable. Mid-year cancellations of Deferral Agreements are permitted only in accordance with Sections 4.02(d), 4.02(i) and/or 6.05, and mid-year suspensions of Deferral Agreements are permitted only in accordance with Section 4.02(i).

(b) A Participant may file a Modification Agreement changing the Benefit Commencement Date and/or Form of Payment for an Account subject to the rules of this Section 4.03(b). A Modification Agreement shall be effective only if (i) it is filed at least 12 months prior to the existing Benefit Commencement Date (determined without regard to a new Benefit Commencement Date under the Modification Agreement) and (ii) except in the case of the death of the Participant, any new Benefit Commencement Date or Form of Payment that is specified under the Modification Agreement results in a delay in payment of at least 5 years. The Administrative Committee may limit Modification Agreements under rules that it may provide from time to time, including restrictions on the Benefit Commencement Dates that may be elected.

(c) The entitlement to installment payments shall be treated as the entitlement to a single payment for purposes of Code Section 409A and applicable administrative guidance thereunder. Based on this treatment, when applying the Modification Agreement restrictions of Section 4.03(b), a change to the Benefit Commencement Date or Form of Payment must result in an additional deferral for a minimum of 5 years from the date that the first installment would have otherwise been paid. For example, a 10 year installment payout scheduled to commence in 2010 could be changed to a lump sum payment payable in 2015 or a series of installment payments commencing in 2015, assuming the other requirements of Section 4.03(b) have been met.

 

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Section 4.04 Discretionary Contributions. As of any date selected by the Employer, the Employer may credit a Participant’s Account with Discretionary Contributions in such amount, if any, as the Employer shall determine in its sole discretion. Such Discretionary Contributions may be made on behalf of some Participants but not others, and such Discretionary Contributions may vary among individual Participants in amount.

ARTICLE V

DEFERRED COMPENSATION ACCOUNTS

Section 5.01 Maintenance of Accounts. Accounts shall be established and maintained for the Deferred Amount and Earnings for each Participant and for each Plan Year, and, in the discretion of the Administrative Committee, separate Accounts for each Plan Year may be established for Deferred Amounts attributable to Base Salary, Incentive Compensation, Unit Distributions, or Discretionary Contributions. Deferred Amounts shall be credited to the Account as of the date such contributions are received by the Trustee of the grantor trust established to fund the Plan pursuant to Article IX, but in no event more than two weeks after the Deferred Amount would otherwise have been paid to the Participant or, in the case of Discretionary Contributions, the date that the Employer awards such amount to the Participant. A Participant’s Account(s) shall be utilized solely as a device for the measurement and determination of the amounts to be paid to the Participant pursuant to this Plan, and shall not constitute or be treated as a trust fund of any kind. The Administrative Committee shall determine the balance of each Account, as of each Valuation Date, by adjusting the balance of such Account as of the immediately preceding Valuation Date to reflect changes in the value of the deemed investments thereof, credits and debits and distributions pursuant to Article VI with respect to such Account since the preceding Valuation Date. To the extent that the Employer is required to withhold any taxes or other amounts from the Deferred Amount pursuant to any state, Federal or local law, Deferred Amounts shall be reduced for such withholdings only to the extent that there is not sufficient cash compensation payable to the Participant at the time that such withholding must be made and such withholding conforms to Code Section 409A.

Section 5.02 Hypothetical Investment Benchmarks. Each Participant shall be entitled to direct the manner in which his Accounts will be deemed to be invested, selecting among the Hypothetical Investment Benchmarks specified by the Administrative Committee from time to time, and in accordance with such rules, regulations and procedures as the Administrative Committee may establish from time to time. If a Participant fails to properly direct the deemed investment of his Accounts, then his Accounts shall be deemed to be invested in the Hypothetical Investment Benchmarks designated by the Administrative Committee from time to time in a uniform and nondiscriminatory manner. Notwithstanding anything to the contrary herein, earnings and losses based on a Participant’s investment elections shall begin to accrue as of the date such Participant’s Deferred Amounts are credited to his/her Accounts.

ARTICLE VI

BENEFITS AND DISTRIBUTIONS

Section 6.01 Time and Form of Payment. Payment of a Participant’s Account shall commence as soon as administratively practicable following the Benefit Commencement Date. The amount of such payment shall be based upon the most

 

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recent Account Valuation Date and shall be paid pursuant to the Form of Payment that is applicable to such Account. Payments shall be made in cash. If the applicable Form of Payment is installments, each annual installment shall be an amount equal to (i) the balance of such Account as of the most recent Valuation Date preceding the payment date, divided by (ii) the number of remaining installments (including the installment being paid).

Section 6.02 Separation from Service Distributions. Notwithstanding Sections 6.01 and 6.03 but subject to Section 6.07, in the event of a Participant’s Separation from Service prior to the Benefit Commencement Date, payment of his Account(s) shall commence as soon as administratively practicable following the Separation from Service and shall be paid in cash in the same Form of Payment elected for distribution upon the Benefit Commencement Date.

Section 6.03 In-Service and Specified Date Distributions. Subject to Section 6.02, if the Benefit Commencement Date applicable to an Account is a specified date, payment of the Account shall commence on the Benefit Commencement Date pursuant to Section 6.01 in the Form of Payment elected by the Participant.

Section 6.04 Distributions in the Event of Death. Notwithstanding the provisions of Sections 6.01, 6.02 and 6.03 or the terms of any Deferral Agreement, if a Participant dies prior to Separation from Service or prior to receiving full payment of his Account(s), the Employer shall pay the remaining balance (determined as of the most recent Valuation Date preceding such event) to the Participant’s Beneficiary or Beneficiaries (as the case may be) as soon as administratively practicable following such event in a lump sum in cash only.

Section 6.05 Hardship Withdrawals. Notwithstanding the provisions of Sections 6.01, 6.02, and 6.03 or of any Deferral Agreement, a Participant shall be entitled to early payment of all or part of the balance in his Account(s) if the Administrative Committee determines in its sole discretion that the standards for a Hardship Withdrawal are satisfied. A Hardship Withdrawal shall be permitted only to the extent reasonably needed to satisfy the unforeseeable emergency that satisfies the standards for a Hardship Withdrawal. An application for an early payment under this Section 6.05 shall be made to the Administrative Committee in such form and in accordance with such procedures as the Administrative Committee shall determine from time to time. The determination of whether and in what amount and form a distribution will be permitted pursuant to this Section 6.05 shall be made by the Administrative Committee. All Deferral Agreements shall terminate upon the Administrative Committee’s determination that a Hardship Withdrawal shall be made.

Section 6.06 Change of Control. In the event of a Change of Control, a Participant’s Account shall be paid as soon as administratively practicable following the Change of Control in a single sum if a Change of Control distribution has been elected by such Participant in the applicable Deferral Agreement.

Section 6.07 Delay for Specified Employees. Notwithstanding anything to the contrary herein, with respect to any payment to be made or to commence upon a Participant’s Separation from Service (other than for death), if such distribution would be subject to additional taxes and interest under Code Section 409A because the timing of the such payment is not delayed as provided in Code Section 409A(a)(2)(B)(i) and the regulations thereunder, such payment(s) to the Participant upon his Separation from

 

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Service (other than for death) shall not be made until the close of the 6-month anniversary of such Separation from Service (or if earlier, upon the death of the Participant pursuant to Section 6.04). If the applicable Form of Payment is installment payments, the second and subsequent installment payments shall occur on the Valuation Date coincident with or next succeeding the anniversary of the date of the Participant’s Separation from Service and each subsequent anniversary of his Separation from Service for the duration of the applicable installment period. The identification of “specified employees,” if any, for purposes of this Section shall be made in accordance with the general requirements of Code Section 409A(a)(2)(B)(i) pursuant to any method elected by the Administrative Committee by written designation or, if no such designation is made, under the default rules under such Code Section.

Section 6.08 Permitted Accelerated Payments. Notwithstanding anything to the contrary in the Plan, the Administrative Committee may direct the accelerated payment of Plan benefits under the following circumstances:

(a) A Participant shall be entitled to receive distribution of all or such portion of his Account, in a single lump sum payment, to the extent necessary for any Federal officer or employee in the executive branch to comply with an ethics agreement with the Federal government;

(b) A Participant shall be entitled to receive distribution of all or such portion of his Account, in a single lump sum payment, to the extent reasonably necessary to avoid the violation of an applicable Federal, state, local or foreign ethics law or conflicts of interest law;

(c) A Participant shall be entitled to receive a distribution of such portion of his Account, in a single lump sum payment, as is necessary to pay (i) the Federal Insurance Contributions Act (FICA) tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2), where applicable, on Compensation deferred under the Plan (the “FICA Amount”), (ii) the income tax at source on wages imposed under Code Section 3401, or the corresponding withholding provisions of applicable state, local, or foreign tax laws as a result of the payment of the FICA Amount, and (iii) to pay the additional income tax at source on wages attributable to the pyramiding Section 3401 wages and taxes; provided, however, that the total payment under this Section 6.08(c) shall not exceed the aggregate of the FICA Amount and the income tax withholding related to such FICA Amount;

(d) A Participant shall be entitled to receive distribution of such portion of his Account, in a single lump sum payment, as is required to be included in the Participant’s income as a result of the failure of the Plan to comply with Code Section 409A; provided, however, that such distribution shall not exceed the amount required to be included in the Participant’s income as a result of such failure;

(e) A Participant shall be entitled to receive distribution of all or such portion of his Account, in a single lump sum payment, to reflect payment of state, local or foreign tax obligations arising from participation in the Plan that apply to an amount deferred under the Plan before the amount is paid or made available to the Participant. Any such payment may not exceed (i) the amount of such taxes as are due as a result of participation in the Plan (the “Other Taxes”) and may be made in the form of withholding pursuant to the provisions of the applicable law or by distribution directly to the Participant and (ii) the income tax at source on wages imposed under Code Section

 

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3401 as a result of the distribution of the Other Taxes and to pay the additional income tax at source on wages imposed under Code Section 3401 attributable to the payment of such additional Code Section 3401 wages and Other Taxes;

(f) A Participant shall be entitled to receive distribution of all or such portion of his Account, in a single lump sum payment, in connection with the settlement of an arms’ length bona fide dispute between the Employer and the Participant as to the Participant’s right to benefits under the Plan to the extent contemplated under Code Section 409A without causing such distribution to be treated as an impermissible acceleration;

(g) A Participant shall be entitled to receive distribution of all or such portion of his Account, in a single lump sum payment, under any other circumstance permitted under Treasury Regulation Section 1.409A-3(j)(4) (except in connection with a qualified domestic relations order) or any successor regulation thereto or prescribed by the Commissioner of Internal Revenue in generally applicable guidance published in the Internal Revenue Bulletin; and

(h) The Administrative Committee may direct, in its discretion, that the balance of each Participant’s Account(s) under the Plan be distributed in connection with a termination of the Plan in accordance with Section 8.02.

Any distribution to be made pursuant to Sections 6.07(a) through (g) shall be made as soon as administratively practicable following the determination that such distribution should be made.

Section 6.09 Withholding of Taxes. Notwithstanding any other provision of this Plan, the Employer shall withhold from payments made hereunder any amounts required to be so withheld by any applicable law or regulation.

Section 6.10 As soon as administratively practicable. For purposes of this Article VI, “as soon as administratively practicable” means a date of distribution that is as soon as administratively practicable as determined by the Administrative Committee following the specified payment date, but in no event later than 90 days after the specified payment date. In no event shall a Participant or his Beneficiary be permitted to designate the taxable year of the payment.

ARTICLE VII

BENEFICIARY DESIGNATION

Section 7.01 Beneficiary Designation. Each Participant shall have the right, at any time, to designate any person, persons or entity as his Beneficiary or Beneficiaries. A Beneficiary designation shall be made, and may be amended, by the Participant by filing a written designation with the Administrative Committee, on such form and in accordance with such procedures as the Administrative Committee shall establish from time to time.

Section 7.02 No Beneficiary Designation. If a Participant fails to designate a Beneficiary as provided above, or if all designated Beneficiaries predecease the Participant, then the Participant’s Beneficiary shall be deemed to be the Participant’s estate.

 

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ARTICLE VIII

AMENDMENT AND TERMINATION OF PLAN

Section 8.01 Amendment and Interpretation. The Board or the Administrative Committee may at any time amend this Plan in whole or in part; provided, however, that no amendment shall be effective to decrease the balance in any Account as accrued at the time of such amendment, except for any decrease that may arise due to future Earnings or distributions; provided further, however, that notwithstanding the foregoing, the Board or the Administrative Committee may make such amendments to the Plan as are necessary or advisable, as determined by the Board or the Administrative Committee in its discretion, to enable the Plan and the Account(s) of Participants established hereunder to comply with the requirements of Code Section 409A. The Board and the Administrative Committee shall use good faith efforts to interpret the Plan in a manner that is consistent with the intent that the Plan conform to the requirements of Code Section 409A.

Section 8.02 Company’s Right to Terminate. Notwithstanding anything to the contrary, the Board or the Administrative Committee may, in their sole discretion, at any time terminate the Plan with respect to future Deferral Agreements. The Board or the Administrative Committee may also terminate the Plan in its entirety and accelerate the time and form of payment of all Accounts under the Plan, under the following circumstances:

(a) The Board or the Administrative Committee may terminate and liquidate the Plan within 12 months of a corporate dissolution taxed under Code Section 331, or with the approval of a bankruptcy court pursuant to 11 U.S.C. § 503(b)(1)(A), provided that the balance of all of the Participants’ Accounts under the Plan are included in the Participants’ respective gross incomes in the latest of (A) the calendar year in which the Plan termination and liquidation occurs or (B) the first calendar year in which the payment is administratively practicable;

(b) The Board or Administrative Committee may, in their discretion, terminate and liquidate the Plan in connection with a Change in Control of the Company (or, with respect to a Participant who is employed by an Employer other than the Company, a Change in Control of such Employer), provided that the following requirements are satisfied:

(i) The Change in Control of such entity constitutes a change in ownership or control of such entity or a substantial portion of its assets within the meaning of Code Section 409A o (a “409A Change in Control”) and the Board or Administrative Committee (or their appropriate counterparts with respect to any Employer other than the Company) takes irrevocable action to terminate and liquidate the Plan within 30 days preceding or 12 months following such 409A Change in Control;

(ii) The vested interest of each Participant in his Account under the Plan and all Other Arrangements (as defined in Paragraph (iii) below) are distributed within 12 months following the date that all necessary action to terminate and liquidate the Plan and the Other Arrangements (as defined in Paragraph (iii) below) is irrevocably taken; and

 

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(iii) All plans, arrangements, methods, programs and other arrangements that are sponsored by the “service recipient” (within the meaning of Code Section 409A), as determined immediately following such 409A Change in Control, with respect to which deferrals of compensation are treated as having been deferred under a single plan under Treasury Regulation Section 1.409A-1(c)(2) (collectively, the “Other Arrangements”), are terminated and liquidated with respect to each Participant who experienced such 409A Change in Control. For purposes of any 409A Change in Control that results from an asset purchase transaction, the applicable “service recipient” with the discretion to liquidate and terminate the Plan and the Other Arrangements shall be the “service recipient” that is primarily liable immediately after the transaction for the payment of the Plan benefits.

(c) The Board or Administrative Committee may, in their discretion, terminate and liquidate the Plan, provided that:

(i) The termination and liquidation does not occur proximate to a down turn in the financial health of the Company and all entities that would be considered a single “service recipient” along with the Company under Code Section 409A;

(ii) Such “service recipient” terminates and liquidates all plans, agreements, methods, programs and other arrangements sponsored by the service recipient that would be aggregated with any terminated and liquidated plans, agreements, methods, programs and other arrangements under Treasury Regulation Section 1.409A-1(c) if the same Participant had deferrals of compensation under all such plans, agreements, methods, programs or other arrangements;

(iii) No payments in liquidation of the Plan are made within 12 months of the date that the Company takes all necessary action to irrevocably terminate and liquidate the Plan, other than payments that would be payable under the terms of such arrangements if the action to terminate and liquidate the Plan had not occurred;

(iv) All payments are made within 24 months of the date that the Company takes all necessary action to irrevocably terminate and liquidate the Plan; and

(v) the Company and all other entities required to be considered a single “service recipient” within the meaning of Code Section 409A do not adopt a new Plan that would be aggregated with any terminated and liquidated plan under Treasury Regulation Section 1.409A-1(c) if the same Participant participated in both plans at any time within three years following the date that the service recipient took all necessary action to irrevocably terminate and liquidate the Plan.

(d) The Board or Administrative Committee may, in their discretion, terminate and liquidate the Plan upon such other events or conditions as the Commissioner of Internal Revenue may prescribe in generally applicable guidance published in the Internal Revenue Bulletin.

 

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In the event that the Plan is terminated, the balance in a Participant’s Accounts shall be paid to such Participant or his Beneficiary in the manner specified by the Board or Administrative Committee (but subject to the distribution timing requirements described above), which may include the payment of a single lump sum payment in full satisfaction of all of such Participant’s or Beneficiary’s benefits hereunder.

ARTICLE IX

NATURE OF THE PLAN

Section 9.01 Establishment of Trust Fund. The Plan is intended to constitute an unfunded, unsecured plan of deferred compensation for a select group of management or highly compensated employees of the Employer. Plan benefits herein provided are a contractual obligation of the Employer which shall be paid out of the Employer’s general assets. Nevertheless, subject to the terms hereof and of the Trust Agreement, the Employer shall transfer money or other property to the Trustee to provide Plan benefits hereunder and the Trustee shall pay Plan benefits to Participants and Beneficiaries out of the Trust in accordance with the terms of the Trust. To the extent that the Employer transfers assets to the Trustee pursuant to the Trust Agreement, the Administrative Committee may, but need not, establish procedures for the Trustees to invest the Trust Fund in accordance with each Participant’s designated deemed investments pursuant to Section 5.02 respecting the portion of the Trust Fund assets equal to such Participant’s Accounts.

Section 9.02 Ownership of Trust Fund Assets. The Employer shall remain the owner of all assets in the Trust Fund and the assets shall be subject to the claims of the Employer’s creditors if the Employer ever becomes insolvent. For purposes hereof, the Employer shall be considered “insolvent” if (a) the Employer is unable to pay its debts as such debts become due or (b) the Employer is subject to a pending proceeding as a debtor under the United Sates Bankruptcy Code (or any successor federal statute). The President of the Employer and its board of directors shall have the duty to inform the Trustee in writing if the Employer becomes insolvent. Such notice given under the preceding sentence by any party shall satisfy all of the parties’ duty to give notice. When so informed, the Trustee shall suspend payments to the Participants and Beneficiaries and hold the assets for the benefit of the Employer’s general creditors. If the Trustee receives a written allegation that the Employer is insolvent, the Trustee shall suspend payments to the Participants and Beneficiaries and hold the Trust Fund for the benefit of the Employer’s general creditors, and shall determine in the manner specified in the Trust Agreement whether the Employer is insolvent. If the Trustee determines that the Employer is not insolvent, the Trustee shall resume payments to the Participants and Beneficiaries. No Participant or Beneficiary shall have any preferred claim to, or any beneficial ownership interest in, any assets of the Trust Fund, and, upon commencement of participation in the Plan, each Participant shall have agreed to waive his priority credit position, if any, under applicable state law with respect to the assets of the Trust Fund.

Section 9.03 Limitation on Funding. Notwithstanding anything to the contrary herein or in the Trust Agreement, in no event shall money and/or property be transferred to the Trust if such transfer would result in adverse tax consequences to a Participant pursuant to Code Section 409A(b).

 

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ARTICLE X

MISCELLANEOUS

Section 10.01 Nonassignability. Except as specifically set forth in the Plan with respect to the designation of Beneficiaries, neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

Section 10.02 Designation of Participating Affiliates. It is contemplated that other Affiliates may be designated to participate in the Plan and thereby become an Employer. Any Affiliate, whether or not presently existing, may become a party hereto if designated to so participate by the Board or by the Administrative Committee. Each of the Affiliates listed on Appendix A to this Plan is an Employer participating in the Plan, and Appendix A may be updated from time to time by the Committee without the requirement of a formal Plan amendment. Except as otherwise provided herein, the provisions of the Plan shall apply separately and equally to each Employer and its employees in the same manner as is expressly provided for the Company and its employees, except that the power to appoint or otherwise affect the Trustee and the power to amend or terminate the Plan or amend the Trust Agreement shall be exercised by the Board or the Administrative Committee alone. Transfer of employment among Companies and Affiliates shall not be considered a termination of employment hereunder and service with one Employer shall be considered service with all others. Any Employer may, by appropriate action of its officers without the need for approval of its board of directors (or noncorporate counterpart), the Board, or the Administrative Committee, terminate its participation in the Plan. Moreover, the Board or the Administrative Committee may, in its discretion, terminate an Employer’s Plan participation at any time, but distributions pursuant to any such termination of an Employer’s participation in the Plan shall be subject to the provisions of Section 8.02 and Treasury Regulation Section 1.409A-3(j)(4)(ix). Notwithstanding the foregoing, the termination of an Employer’s Plan participation may be effective only as of the end of a Plan Year if the Employer remains an Affiliate of the Company following such termination or, if the Employer does not remain as an Affiliate of the Company at such time, the termination shall be effective only at a time that complies with Code Section 409A.

 

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APPENDIX A

PARTICIPATING AFFILIATES

As of January 1, 2010, the Affiliates participating in the Plan and the effective dates of their participation are as follows:

 

PARTICIPATING AFFILIATES		EFFECTIVE DATE OF PARTICIPATION
Energy Transfer Partners GP, L.P. (Plan sponsor)		January 1, 2010
Heritage Operating, L.P.		January 1, 2010
Heritage Services Corp.		January 1, 2010
LaGrange Acquisition, L.P. d/b/a Energy Transfer Company		January 1, 2010
Titan Propane LLC		January 1, 2010
Titan Propane Services, Inc.		January 1, 2010
Energy Transfer Equity, L.P.		January 1, 2010
Transwestern Pipeline Company, LLC		January 1, 2010
Energy Transfer Group, L.L.C.		January 1, 2010
Energy Transfer Technologies, Ltd.		January 1, 2010
SEC Energy Products & Services LP d/b/a Standard Equipment Company		January 1, 2010

 

PAGE A-1

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: May 7, 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 March 31, 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: May 7, 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.