exhibit99

EXHIBIT 99.4

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries

	Page


Report of Independent Registered Public Accounting Firm	2

Consolidated Balance Sheets – December 31, 2009 and 2008	3

Consolidated Statements of Operations – Years Ended December 31, 2009 and 2008,
Four Months Ended December 31, 2007 and Year Ended August 31, 2007	5

Consolidated Statements of Comprehensive Income – Years Ended December 31, 2009 and 2008,
Four Months Ended December 31, 2007 and Year Ended August 31, 2007	6

Consolidated Statements of Equity –
Years Ended December 31, 2009 and 2008, Four Months Ended December 31, 2007 and Year Ended August 31, 2007	7

Consolidated Statements of Cash Flows – Years Ended December 31, 2009 and 2008,
Four Months Ended December 31, 2007 and Year Ended August 31, 2007	8

Notes to Consolidated Financial Statements	9

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Energy Transfer Equity, L.P.

We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the two years in the period ended December 31, 2009, the four months ended December 31, 2007, and the year ended August 31, 2007. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, the four months ended December 31, 2007, and the year ended August 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the Partnership retrospectively adopted a new accounting pronouncement on January 1, 2009 related to the accounting for noncontrolling interests in consolidated financial statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Energy Transfer Equity, L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 24, 2010 (not separately included herein), expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 24, 2010

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31, 2009		December 31, 2008

ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	68,315	$	92,023
Marketable securities		6,055		5,915
Accounts receivable, net of allowance for doubtful accounts		566,522		591,257
Accounts receivable from related companies		51,894		15,142
Inventories		389,954		272,348
Exchanges receivable		23,136		45,209
Price risk management assets		12,371		5,423
Other current assets		149,712		153,678
Total current assets		1,267,959		1,180,995

PROPERTY, PLANT AND EQUIPMENT, net		9,064,475		8,702,534
ADVANCES TO AND INVESTMENT IN AFFILIATES		663,298		10,110
GOODWILL		775,094		773,283
INTANGIBLES AND OTHER ASSETS, net		389,683		402,980
Total assets	$	12,160,509	$	11,069,902

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31, 2009			December 31, 2008

LIABILITIES AND EQUITY

CURRENT LIABILITIES:
Accounts payable	$	359,176		$	381,933
Accounts payable to related companies		38,515			34,495
Exchanges payable		19,203			54,636
Price risk management liabilities		65,146			142,432
Interest payable		137,708			115,487
Accrued and other current liabilities		229,073			434,706
Current maturities of long-term debt		40,924			45,232
Total current liabilities		889,745			1,208,921

LONG-TERM DEBT, less current maturities		7,750,998			7,190,357
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		73,332			121,710
DEFERRED INCOME TAXES		204,373			194,871
OTHER NON-CURRENT LIABILITIES		21,810			14,727

COMMITMENTS AND CONTINGENCIES (Note 11)
		8,940,258			8,730,586

EQUITY:
PARTNERS’ CAPITAL (DEFICIT):
General Partner		368			155
Limited Partners:
Common Unitholders (222,898,248 and 222,829,956 units authorized, issued and outstanding at December 31, 2009 and 2008, respectively)		53,412			(15,762	)

Accumulated other comprehensive loss		(53,628	)		(67,825	)
Total partners’ capital (deficit)		152			(83,432	)
Noncontrolling interest		3,220,099			2,422,748
Total equity		3,220,251			2,339,316

Total liabilities and equity	$	12,160,509		$	11,069,902

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007
REVENUES:
Natural gas operations	$	4,115,806		$	7,653,156		$	1,832,192		$	5,385,892
Retail propane		1,190,524			1,514,599			471,494			1,179,073
Other		110,965			125,612			45,656			227,072
Total revenues		5,417,295			9,293,367			2,349,342			6,792,037

COSTS AND EXPENSES:
Cost of products sold - natural gas operations		2,519,575			5,885,982			1,343,237			4,207,700
Cost of products sold - retail propane		574,854			1,014,068			315,698			734,204
Cost of products sold - other		27,627			38,030			14,719			136,302
Operating expenses		680,893			781,831			221,757			559,600
Depreciation and amortization		325,024			274,372			75,406			191,383
Selling, general and administrative		178,924			200,181			61,874			153,512
Total costs and expenses		4,306,897			8,194,464			2,032,691			5,982,701

OPERATING INCOME		1,110,398			1,098,903			316,651			809,336

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(468,420	)		(357,541	)		(103,375	)		(279,986	)
Equity in earnings (losses) of affiliates		20,597			(165	)		(94	)		5,161
Gains (losses) on disposal of assets		(1,564	)		(1,303	)		14,310			(6,310	)
Gains (losses) on non-hedged interest rate derivatives		33,619			(128,423	)		(28,683	)		29,081
Allowance for equity funds used during construction		10,557			63,976			7,276			4,948
Other, net		1,913			8,115			(13,327	)		1,129

INCOME BEFORE INCOME TAX EXPENSE		707,100			683,562			192,758			563,359
Income tax expense		9,229			3,808			9,949			11,391

NET INCOME		697,871			679,754			182,809			551,968

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		255,398			304,710			90,132			232,608

NET INCOME ATTRIBUTABLE TO PARTNERS		442,473			375,044			92,677			319,360

GENERAL PARTNER'S INTEREST IN NET INCOME		1,370			1,161			287			1,048

LIMITED PARTNERS' INTEREST IN NET INCOME	$	441,103		$	373,883		$	92,390		$	318,312

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	1.98		$	1.68		$	0.41		$	1.56

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,898,203			222,829,956			222,829,916			204,578,719

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	1.98		$	1.68		$	0.41		$	1.55

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,898,203			222,829,956			222,829,916			204,578,719

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007

Net income	$	697,871		$	679,754		$	182,809		$	551,968

Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		16,958			(22,916	)		(17,970	)		(163,378	)
Change in value of derivative instruments accounted for as cash flow hedges		(11,017	)		(40,350	)		(2,221	)		179,861
Change in value of available-for-sale securities		10,923			(6,418	)		(98	)		280
		16,864			(69,684	)		(20,289	)		16,763

Comprehensive income		714,735			610,070			162,520			568,731

Less: Comprehensive income attributable to noncontrolling interest		258,066			291,624			92,832			239,885

Comprehensive income attributable to partners	$	456,669		$	318,446		$	69,688		$	328,846

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(Dollars in thousands)

	General Partner			Common Unitholders			Class B Unitholders			Class C Unitholders			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Balance, August 31, 2006	$	(69	)	$	(9,586	)	$	53,130		$	-		$	2,276		$	1,439,127		$	1,484,878
Unit issuances		-			372,638			-			4,456			-			(4,456	)		372,638
Equity issue costs of Class C Units		-			-			-			(204	)		-			-			(204	)
Assumption of related company debt		-			-			-			(70,500	)		-			-			(70,500	)
Distribution to partners		(955	)		(246,136	)		(1,645	)		(28,261	)		-			-			(276,997	)
Subsidiary distributions and other		-			-			-			-			-			(252,584	)		(252,584	)
Purchase premium on ETP Class G Units		-			(451,150	)		-			-			-			451,150			-
Tax effect of remedial income allocation from tax amortization of goodwill		-			-			-			-			-			(1,161	)		(1,161	)
Non-cash unit-based compensation expense		-			28			-			-			-			10,471			10,499
Other comprehensive income, net of tax		-			-			-			-			9,486			7,277			16,763
Net income		1,048			260,184			2,524			55,604			-			232,608			551,968
Conversion to Common Units		-			15,104			(54,009	)		38,905			-			-			-
Balance, August 31, 2007		24			(58,918	)		-			-			11,762			1,882,432			1,835,300
Distributions to partners		(270	)		(86,904	)		-			-			-			-			(87,174	)
Subsidiary distributions and other		-			-			-			-			-			(63,756	)		(63,756	)
Tax effect of remedial income allocation from tax amortization of goodwill		-			-			-			-			-			(1,161	)		(1,161	)
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings		-			23			-			-			-			7,950			7,973
Non-cash executive compensation expense		-			-			-			-			-			1,167			1,167
Subsidiary sale of common units		151			48,781			-			-			-			187,355			236,287
Other comprehensive loss, net of tax		-			-			-			-			(22,989	)		2,700			(20,289	)
Net income		287			92,390			-			-			-			90,132			182,809
Balance, December 31, 2007		192			(4,628	)		-			-			(11,227	)		2,106,819			2,091,156
Distributions to partners		(1,349	)		(434,519	)		-			-			-			-			(435,868	)
Subsidiary distributions		-			-			-			-			-			(319,963	)		(319,963	)
Tax effect of remedial income allocation from tax amortization of goodwill		-			-			-			-			-			(3,407	)		(3,407	)
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings		-			823			-			-			-			19,968			20,791
Non-cash executive compensation expense		-			48			-			-			-			1,202			1,250
Subsidiary sale of common units		151			48,631			-			-			-			326,505			375,287
Other comprehensive loss, net of tax		-			-			-			-			(56,598	)		(13,086	)		(69,684	)
Net income		1,161			373,883			-			-			-			304,710			679,754
Balance, December 31, 2008		155			(15,762	)		-			-			(67,825	)		2,422,748			2,339,316
Distributions to ETE partners		(1,457	)		(469,201	)		-			-			-			-			(470,658	)
Subsidiary distributions		-			-			-			-			-			(381,471	)		(381,471	)
Subsidiary sale of common units		300			96,696			-			-			-			902,680			999,676
Tax effect of remedial income allocation from tax amortization of goodwill		-			-			-			-			-			(3,762	)		(3,762	)
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings		-			551			-			-			-			20,613			21,164
Non-cash executive compensation expense		-			25			-			-			-			1,225			1,250
Other comprehensive loss, net of tax		-			-			-			-			14,197			2,668			16,865
Net income		1,370			441,103			-			-			-			255,398			697,871
Balance, December 31, 2009	$	368		$	53,412		$	-		$	-		$	(53,628	)	$	3,220,099		$	3,220,251

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	697,871		$	679,754		$	182,809		$	551,968
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		325,024			274,372			75,406			191,383
Amortization of finance costs charged to interest		14,954			10,962			2,441			6,691
Provision for loss on accounts receivable		2,992			8,015			544			4,229
Goodwill impairment		-			11,359			-			-
Non-cash unit-based compensation expense		24,583			24,304			8,137			10,499
Non-cash executive compensation expense		1,250			1,250			442			-
Deferred income taxes		8,422			(8,177	)		37			(6,939	)
(Gains) losses on disposal of assets		1,564			1,303			(14,310	)		6,310
Distribution in excess of (less than) earnings of affiliates, net		3,224			5,621			4,448			(5,161	)
Other non-cash		(4,468	)		3,382			(2,069	)		(760	)
Net change in operating assets and liabilities, net of effects of acquisitions		(351,955	)		131,575			(49,250	)		248,100
Net cash provided by operating activities		723,461			1,143,720			208,635			1,006,320

CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash (paid for) received in acquisitions		30,367			(84,783	)		(337,092	)		(90,695	)
Capital expenditures		(748,621	)		(2,054,806	)		(651,228	)		(1,107,127	)
Contributions in aid of construction costs		6,453			50,050			3,493			10,463
(Advances to) repayments from affiliates		(655,500	)		54,534			(32,594	)		(993,866	)
Proceeds from the sale of assets		21,545			19,420			21,478			23,135
Net cash used in investing activities		(1,345,756	)		(2,015,585	)		(995,943	)		(2,158,090	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		3,542,612			6,205,994			1,742,802			6,010,633
Principal payments on debt		(3,020,587	)		(4,890,619	)		(1,062,272	)		(4,628,052	)
Net proceeds from issuance of Common Units		-			-			-			372,434
Subsidiary equity offerings, net of issue costs		936,337			373,059			234,887			-
Distributions to partners		(470,658	)		(435,868	)		(87,174	)		(276,997	)
Debt issuance costs		(7,646	)		(25,272	)		(211	)		(23,279	)
Distributions to noncontrolling interests		(381,471	)		(319,963	)		(61,517	)		(251,823	)
Net cash provided by financing activities		598,587			907,331			766,515			1,202,916

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(23,708	)		35,466			(20,793	)		51,146

CASH AND CASH EQUIVALENTS, beginning of period		92,023			56,557			77,350			26,204

CASH AND CASH EQUIVALENTS, end of period	$	68,315		$	92,023		$	56,557		$	77,350

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1.	OPERATIONS AND ORGANIZATION:

Financial Statement Presentation

The consolidated financial statements of Energy Transfer Equity, L.P. and subsidiaries (the “Partnership”, “ETE” or the “Parent Company”) presented herein for the years ended December 31, 2009 and 2008, the four months ended December 31, 2007 and the year ended August 31, 2007, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. We present equity and net income attributable to noncontrolling interest for all partially-owned consolidated subsidiaries. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through February 24, 2010, the date the financial statements were issued.

The consolidated financial statements of the Partnership presented herein include the results of operations for 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. (“ETP GP”), the General Partner of ETP, and Energy Transfer Partners, L.L.C. (“ETP LLC”), the General Partner of ETP GP. The results of operations for ETP include its wholly-owned subsidiaries: La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”); Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”); ETC Fayetteville Express Pipeline, LLC (“ETC FEP”); ETC Tiger Pipeline, LLC (“ETC Tiger”); Heritage Operating, L.P. (“HOLP”); Heritage Holdings, Inc. (“HHI”); and Titan Energy Partners, L.P. (“Titan”). The operations of ET Interstate are included since the date of the Transwestern acquisition on December 1, 2006. ETC FEP and ETC Tiger are included since their inception dates on August 27, 2008 and June 20, 2008, respectively. The operations of all other subsidiaries listed above are reflected for all periods presented.

We also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

In November 2007, we changed our fiscal year end to the calendar year. Thus, a new fiscal year began on January 1, 2008. The Partnership completed a four-month transition period that began September 1, 2007 and ended December 31, 2007 and filed a transition report on Form 10-Q for that period in February 2008. The financial statements contained herein cover the years ended December 31, 2009 and 2008, the four months ended December 31, 2007, and the year ended August 31, 2007.

We did not recast the financial data for the prior fiscal periods because the financial reporting processes in place at that time included certain procedures that were completed only on a fiscal quarterly basis. Consequently, to recast those periods would have been impractical and would not have been cost-justified. Such comparability is impacted primarily by weather, fluctuations in commodity prices, volumes of natural gas sold and transported, our hedging strategies and the use of financial instruments, trading activities, basis differences between market hubs and interest rates. We believe that the trends indicated by comparison of the results for the years ended December 31, 2009 and 2008 are substantially similar to what is reflected in the information for the year ended August 31, 2007.

Certain prior period amounts have been reclassified to conform to the 2009 presentation. Other than the reclassifications related to the adoption of Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51, which is now incorporated into ASC 810-10-65 (see Note 2), 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 17 for stand-alone financial information apart from that of the consolidated partnership information included herein.

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 our operating subsidiaries (collectively the “Operating Companies”) as follows:

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, Arizona, 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.

ET Interstate, the parent company of Transwestern and 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, a Delaware limited liability company formed to engage in interstate transportation of natural gas.

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

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, 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” shall mean Energy Transfer Equity, L.P. on a stand-alone basis.

ETC OLP owns an interest in and operates approximately 14,800 miles of in service natural gas gathering and intrastate transportation pipelines, three natural gas processing plants, eleven natural gas treating facilities, eleven natural gas conditioning facilities and three natural gas storage facilities located in Texas.

Revenue in our intrastate transportation and storage operations is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The intrastate transportation and storage operations also consist of the HPL System, which 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. The HPL System also transports natural gas for a variety of third party customers. Our intrastate transportation and storage segment also generates revenues from fees charged for storing customers’ working natural gas in our storage facilities. In addition, the use of the Bammel storage facility allows us to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin.

Our interstate transportation operations principally focus on natural gas transportation of Transwestern, which owns and operates approximately 2,700 miles of interstate natural gas pipeline, with an additional 180 miles under construction, extending from Texas through the San Juan Basin to the California border. In addition, we have interests in joint ventures that have 500 miles of interstate natural gas pipeline and 185 miles under construction. Transwestern is a major natural gas transporter to the California border and delivers natural gas from the east end of its system to Texas intrastate and Midwest markets. The Transwestern pipeline interconnects with our existing intrastate pipelines in West Texas. The revenues of this segment consist primarily of fees earned from natural gas transportation services and operational gas sales.

Revenue in our midstream operations is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipelines (excluding the interstate transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices.

Our retail propane segment sells propane and propane-related products and services. The HOLP and Titan customer base includes residential, commercial, industrial and agricultural customers.

2.	ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

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 year ended December 31, 2009 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.

Revenue Recognition

Revenues for sales of natural gas, NGLs including propane, and propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenues from service labor, transportation, treating, compression and gas processing, are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Tank rent is recognized ratably over the period it is earned.

Our intrastate transportation and storage and interstate transportation segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) a fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.

Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from the midstream segment’s marketing operations, and from producers at the wellhead.

In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and gross margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.

We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

We conduct marketing activities 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 supply points 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.

We have a risk management policy that provides for oversight over our marketing activities. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. As a result of our use of derivative financial instruments that may not qualify for hedge accounting, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to senior management and predefined limits and authorizations set forth in our risk management policy.

Regulatory Accounting - Regulatory Assets and Liabilities

Transwestern, part of our interstate transportation segment, is subject to regulation by certain state and federal authorities and has accounting policies that conform to Statement of Financial Accounting Standards No. 71 (As Amended), Accounting for the Effects of Certain Types of Regulation, now incorporated into ASC 980, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

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.

As a result of our acquisition of a natural gas compression equipment business in exchange for ETP Common Units, cash acquired in connection with acquisitions during 2009 exceeded the cash we paid by $30.4 million.

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

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007
Accounts receivable	$	28,431		$	220,635		$	(169,263	)	$	54,347
Accounts receivable from related companies		(26,321	)		3,234			(12,091	)		(5,376	)
Inventories		(101,592	)		96,145			(168,430	)		196,173
Exchanges receivable		22,074			(7,888	)		(4,216	)		(3,406	)
Other current assets		8,195			(57,150	)		(4,459	)		53,591
Intangibles and other assets		(4,786	)		(40,753	)		605			(1,817	)
Accounts payable		(16,024	)		(296,185	)		195,574			(92,296	)
Accounts payable to related companies		4,184			(13,538	)		28,876			18,560
Exchanges payable		(35,433	)		14,254			6,117			3,000
Accrued and other current liabilities		(124,147	)		32,474			1,026			(26,794	)
Interest payable		22,220			36,501			41,640			18,181
Other long-term liabilities		1,401			1,741			(680	)		1,460
Price risk management liabilities, net		(130,157	)		142,105			36,051			32,477
Net change in assets and liabilities, net of effect of acquisitions	$	(351,955	)	$	131,575		$	(49,250	)	$	248,100

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

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007
NON-CASH INVESTING ACTIVITIES:
Transfer of investment in affiliate in purchase of Transwestern (Note 3)	$	-	$	-	$	-	$	956,348

Investment in Calpine Corporation received in exchange for accounts receivable	$	-	$	10,816	$	-	$	-

Capital expenditures accrued	$	46,134	$	153,230	$	87,622	$	43,498

Gain from subsidiary issuance of common units (recorded in partners' capital)	$	96,996	$	48,782	$	48,932	$	-

NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	26,237	$	5,077	$	3,896	$	533,625

Subsidiary issuance of Common Units in connection with certain acquisitions	$	63,339	$	2,228	$	1,400	$	-

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	440,492	$	330,816	$	79,084	$	283,854

Cash paid for income taxes	$	15,447	$	5,191	$	9,135	$	8,962

Marketable Securities

Marketable securities are classified as available-for-sale securities and are reflected as current assets on the consolidated balance sheets at fair value.

During the year ended December 31, 2008, we determined there was an other-than-temporary decline in the market value of one of our available-for-sale securities, and reclassified into earnings a loss of $1.4 million, which is recorded in other expense. Unrealized holding gains (losses), net of tax, of $7.4 million, $(6.4) million, $(0.1) million and $0.3 million, were recorded through accumulated other comprehensive income (“AOCI”), based on the market value of the securities, for the years ended December 31, 2009 and 2008, the four months ended December 31, 2007, and the fiscal year ended August 31, 2007, respectively. The change in value of our available-for-sale securities for the year ended December 31, 2009 includes realized losses of $3.5 million reclassified from AOCI during the period as discussed in “Accounts Receivable” below.

Accounts Receivable

Our midstream and intrastate transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master setoff agreement). Management reviews midstream and intrastate transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and intrastate transportation and storage operations. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Management believes that the occurrence of bad debt in our midstream and intrastate transportation and storage segments was not significant at December 31, 2009 or 2008; therefore, an allowance for doubtful accounts for the midstream and intrastate transportation and storage segments was not deemed necessary.

ETP’s interstate transportation operations have a concentration of customers in the electric and gas utility industries as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral. Transwestern’s management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Transwestern establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables. Transwestern considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectability.

ETP’s propane operations grant credit to their customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane and Titan’s retail propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane operations are recorded as amounts are billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the propane segment is based on management’s assessment of the realizability of customer accounts, based on the overall creditworthiness of our customers and any specific disputes.

We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.

We exchanged a portion of our outstanding accounts receivable from Calpine Energy Services, L.P. for Calpine Corporation (“Calpine”) common stock valued at $10.8 million during the first quarter of 2008 pursuant to a settlement reached with Calpine related to their bankruptcy reorganization. The stock is included in marketable securities on the consolidated balance sheet at a fair value of $4.8 million as of December 31, 2008. In 2009, we sold the stock for $7.3 million and recorded a realized loss of $3.6 million, of which $3.5 million was reclassified from AOCI to other income in the consolidated statement of operations.

Accounts receivable consisted of the following:

	December 31, 2009			December 31, 2008
Natural gas operations	$	429,849		$	444,816
Propane		143,011			155,191
Less – allowance for doubtful accounts		(6,338	)		(8,750	)
Total, net	$	566,522		$	591,257

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

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007
Balance, beginning of the period	$	8,750		$	5,698		$	5,601		$	4,000
Accounts receivable written off, net of recoveries		(5,404	)		(4,963	)		(447	)		(2,628	)
Provision for loss on accounts receivable		2,992			8,015			544			4,229
Balance, end of period	$	6,338		$	8,750		$	5,698		$	5,601

Inventories

Inventories consist principally of natural gas held in storage valued at the lower of cost or market utilizing the weighted-average cost method. Propane inventories are also valued at the lower of cost or market utilizing the weighted-average cost of propane delivered to the customer service locations, including storage fees and inbound freight costs. The cost of appliances, parts and fittings is determined by the first-in, first-out method.

Inventories consisted of the following:

	December 31, 2009		December 31, 2008
Natural gas and NGLs, excluding propane	$	157,103	$	184,727
Propane		66,686		63,967
Appliances, parts and fittings and other		166,165		23,654
Total inventories	$	389,954	$	272,348

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. In April 2009, we began designating commodity derivatives as fair value hedges for accounting purposes. Subsequent to the designation of those fair value hedging relationships, changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheet and have been recorded in cost of products sold in our consolidated statements of operations.

During 2009, we recorded lower of cost or market adjustments of $54.0 million, which were offset by fair value adjustments related to our application of fair value hedging of $66.1 million.

During 2008, we recorded lower-of-cost-or-market adjustments of $69.5 million for natural gas inventory and $4.4 million for propane inventory to reflect market values, which were less than the weighted-average cost. The natural gas inventory adjustment in 2008 was partially offset in net income by the recognition of unrealized gains on related cash flow hedges in the amount of $21.7 million from AOCI.

Exchanges

The midstream and intrastate transportation and storage segments’ exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. Management believes market value approximates cost.

The interstate transportation segment’s natural gas imbalances occur as a result of differences in volumes of gas received and delivered. Transwestern records natural gas imbalances for in-kind receivables and payables at the dollar weighted composite average of all current month gas transactions and dollar valued imbalances are recorded at contractual prices.

Other Current Assets

Other current assets consisted of the following:

	December 31, 2009		December 31, 2008
Deposits paid to vendors	$	79,694	$	78,237
Prepaid and other		70,018		75,441
Total other current assets	$	149,712	$	153,678

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or Federal Energy Regulatory Commission (“FERC”) mandated lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.

We review property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. No impairment of long-lived assets was required during the periods presented.

Capitalized interest is included for pipeline construction projects, except for interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of ETP’s revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:

	December 31, 2009			December 31, 2008
Land and improvements	$	87,388		$	74,895
Buildings and improvements (10 to 40 years)		160,912			133,951
Pipelines and equipment (10 to 83 years)		7,388,889			5,592,057
Natural gas storage (40 years)		100,746			92,457
Bulk storage, equipment and facilities (3 to 83 years)		591,908			533,621
Tanks and other equipment (10 to 30 years)		602,915			578,118
Vehicles (3 to 10 years)		176,946			156,486
Right of way (20 to 83 years)		516,709			366,205
Furniture and fixtures (3 to 10 years)		32,810			28,075
Linepack		53,404			48,108
Pad gas		47,363			53,583
Other (5 to 10 years)		117,896			97,975
		9,877,886			7,755,531
Less – Accumulated depreciation		(1,052,566	)		(762,014	)
		8,825,320			6,993,517
Plus – Construction work-in-process		239,155			1,709,017
Property, plant and equipment, net	$	9,064,475		$	8,702,534

We recognized the following amounts of depreciation expense, capitalized interest, and AFUDC for the periods presented:

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007
Depreciation expense	$	304,129	$	256,910	$	68,642	$	175,851
Capitalized interest, excluding AFUDC	$	11,791	$	21,595	$	12,657	$	22,979
AFUDC (both debt and equity components)	$	10,237	$	50,074	$	5,095	$	3,600

Advances to and Investment in Affiliates

We own interests in a number of related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we have a 20% to 50% ownership and exercise significant influence over, but do not control the investee’s operating and financial policies.

We account for our investments in Midcontinent Express Pipeline LLC and Fayetteville Express Pipeline LLC using the equity method. See Note 4 for a discussion of these joint ventures.

Goodwill

Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of December 31 for subsidiaries in our interstate segment and as of August 31 for all others. At December 31, 2008, we recorded an impairment of the entire goodwill balance of $11.4 million related to the Canyon Gathering System. No other goodwill impairments were recorded for the periods presented in these consolidated financial statements. Changes in the carrying amount of goodwill were as follows:

	Intrastate Transportation and Storage		Interstate Transportation		Midstream			Retail Propane			All Other		Total
Balance as of December 31, 2007	$	10,327	$	98,613	$	24,368		$	594,801		$	29,589	$	757,698
Purchase accounting adjustments		-		-		-			2,457			-		2,457
Goodwill acquired		-		-		9,141			15,346			-		24,487
Goodwill impairment		-		-		(11,359	)		-			-		(11,359	)
Balance as of December 31, 2008		10,327		98,613		22,150			612,604			29,589		773,283
Purchase accounting adjustments		-		-		-			(8,662	)		-		(8,662	)
Goodwill acquired		-		-		-			33			10,440		10,473
Balance as of December 31, 2009	$	10,327	$	98,613	$	22,150		$	603,975		$	40,029	$	775,094

Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.

Intangibles and Other Assets

Intangibles and other assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangibles and other assets were as follows:

	December 31, 2009					December 31, 2008
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Noncompete agreements (3 to 15 years)	$	24,139	$	(12,415	)	$	40,301	$	(24,374	)
Customer lists (3 to 30 years)		153,843		(53,123	)		144,337		(39,730	)
Contract rights (6 to 15 years)		23,015		(5,638	)		23,015		(3,744	)
Patents (9 years)		750		(35	)		-		-
Other (10 years)		478		(397	)		2,677		(2,244	)
Total amortizable intangible assets		202,225		(71,608	)		210,330		(70,092	)

Non-amortizable intangible assets:
Trademarks		75,825		-			75,667		-
Total intangible assets		278,050		(71,608	)		285,997		(70,092	)

Other assets:
Financing costs (3 to 30 years)		84,099		(34,702	)		74,611		(23,508	)
Regulatory assets		101,879		(9,501	)		98,560		(5,941	)
Other assets		41,466		-			43,353		-
Total intangibles and other assets	$	505,494	$	(115,811	)	$	502,521	$	(99,541	)

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

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007

Reported in depreciation and amortization	$	20,895	$	17,462	$	6,764	$	15,532

Reported in interest expense	$	11,195	$	9,015	$	2,716	$	7,132

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

Years Ending December 31:
2010	$	29,962
2011		27,553
2012		22,117
2013		16,310
2014		15,343

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Our annual impairment test is performed as of December 31 for our interstate segment and as of August 31 for all others. No impairment of intangible assets was required during the periods presented in these consolidated financial statements.

Asset Retirement Obligation

We record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, we also recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.

We have determined that we are obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates. However, management was not able to reasonably measure the fair value of the asset retirement obligations as of December 31, 2009 or 2008 because the settlement dates were indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	December 31, 2009		December 31, 2008
Customer advances and deposits	$	88,430	$	106,679
Accrued capital expenditures		46,134		153,230
Accrued wages and benefits		25,577		65,754
Taxes other than income taxes		23,294		20,772
Income taxes payable		3,154		14,298
Deferred income taxes		-		589
Other		42,484		73,384
Total accrued and other current liabilities	$	229,073	$	434,706

Customer Advances and Deposits

Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month and from our propane customers as security or prepayments for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Fair Value of Financial Instruments

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 December 31, 2009 was $8.25 billion and $7.79 billion, respectively. At December 31, 2008, the aggregate fair value and carrying amount of long-term debt was $6.41 billion and $7.24 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 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. 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 our credit risk. We currently do not have any fair value measurements that require the use of significant unobservable inputs and therefore do not have any assets or liabilities considered as Level 3 valuations.

The following table summarizes the fair value of our financial assets and liabilities as of December 31, 2009 and 2008 based on inputs used to derive their fair values:

	Fair Value Measurements at at December 31, 2009 Using									Fair Value Measurements at December 31, 2008 Using
	Fair Value			Quoted Prices in Active Markets for Identical Assets and Liabilities			Significant Other Observable Inputs			Fair Value			Quoted Prices in Active Markets for Identical Assets and Liabilities		Significant Other Observable Inputs
Description	Total			(Level 1)			(Level 2)			Total			(Level 1)		(Level 2)

Assets:
Marketable securities	$	6,055		$	6,055		$	-		$	5,915		$	5,915	$	-
Inventories		156,156			156,156			-			-			-		-
Commodity derivatives		32,479			20,090			12,389			111,513			106,090		5,423

Liabilities:
Commodity derivatives		(8,016	)		(7,574	)		(442	)		(43,336	)		-		(43,336	)
Interest rate swap derivatives		(138,036	)		-			(138,036	)		(220,806	)		-		(220,806	)
	$	48,638		$	174,727		$	(126,089	)	$	(146,714	)	$	112,005	$	(258,719	)

Contributions in Aid of Construction Costs

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized. In March 2008, we received a reimbursement related to an extension on our Southeast Bossier pipeline resulting in an excess over total project costs of $7.1 million, which is recorded in other income on our consolidated statement of operations for the year ended December 31, 2008.

Contributions in aid of construction costs were as follows:

	Years Ended December 31,					Four Months Ended December 31,		Year Ended August 31,
	2009			2008		2007		2007

Received and netted against project costs	$	6,453		$	50,050	$	3,493	$	10,463

Recorded in other income		(305	)		8,352		216		403

Total	$	6,148		$	58,402	$	3,709	$	10,866

Shipping and Handling Costs

Shipping and handling costs related to fuel sold are included in cost of products sold. Shipping and handling costs related to fuel consumed for compression and treating are included in operating expenses and totaled $55.9 million and $112.0 million for the years ended December 31, 2009 and 2008, respectively, $30.7 million for the four months ended December 31, 2007, and $58.6 million for the year ended August 31, 2007. We do not separately charge propane shipping and handling costs to customers.

Costs and Expenses

Costs of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, storage fees and inbound freight on propane, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, shipping and handling costs related to propane, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.

We record the collection of taxes to be remitted to governmental authorities on a net basis.

Issuances of Subsidiary Units

We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon ETP’s issuance of ETP Common Units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.

Income Taxes

ETE is a limited partnership. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under the Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).

Our partnership will be considered to have terminated for federal income tax purposes if transfers of units within a 12-month period constitute the sale or exchange of 50% or more of our capital and profits interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior 12-month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.

We exceeded the 50% threshold on May 7, 2007, and, as a result, our partnership terminated for federal tax income purposes on that date. Our termination also caused ETP to terminate for federal income tax purposes on that date. These terminations did not affect our classification or the classification of ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. These terminations required both us and ETP to close our taxable years and to make new elections as to various tax matters. In addition, ETP was required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule resulted in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the Unitholders of ETP and, consequently, to our Unitholders. However, elections ETP and ETE made with respect to the amortization of certain intangible assets had the effect of reducing the amount of taxable income that would otherwise be allocated to ETE Unitholders.

As a result of the tax termination discussed above, we elected new depreciation and amortization policies for income tax purposes, which include the amortization of goodwill. As a result of the income tax regulations related to remedial income allocations, ETP’s subsidiary, Heritage Holdings, Inc. (“HHI”), which owns ETP’s Class E units, receives a special allocation of taxable income, for income tax purposes only, essentially equal to the amount of goodwill amortization deductions allocated to purchasers of ETP Common Units. The amount of such “goodwill” accumulated as of the date of ETP’s acquisition of HHI (approximately $158.0 million) is now being amortized over 15 years beginning on May 7, 2007, the date of our new tax elections. ETP accounts for HHI using the treasury stock method due to its ownership of ETP’s Class E units. ETP accounts for the tax effects of the goodwill amortization and remedial income allocation as an adjustment of ETP’s HHI purchase price allocation, which effectively results in a charge to ETP’s common equity and a deferred tax benefit offsetting the current tax expense resulting from the remedial income allocation for tax purposes. For the years ended December 31, 2009 and 2008, the four months ended December, 31, 2007, and the year ended August 31, 2007, this resulted in a current tax expense and deferred tax benefit (with a corresponding charge to common equity as an adjustment of the purchase price allocation) of approximately $3.8 million, $3.4 million, $1.2 million and $1.2 million, respectively. As of December 31, 2009, the amount of tax goodwill to be amortized over the next 13 years for which HHI will receive a remedial income allocation is approximately $132.8 million.

As a limited partnership, we are generally not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualifying income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the years ended December 31, 2009 and 2008, the four months ended December 31, 2007 and the year ended August 31, 2007, our non-qualifying income did not exceed the statutory limit.

Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes, under which deferred income taxes are recorded based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.

Accounting for Derivative Instruments and Hedging Activities

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 and swaps 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.

For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.

If we designate a hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.

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 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, either through mark-to-market or the physical withdrawal of natural gas.

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.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.

If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.

We are exposed to market risk for changes in interest rates related to our revolving credit facilities. We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to effectively convert a portion of variable rate debt into fixed rate debt. Certain of our interest rate derivatives are accounted for as cash flow hedges. We report the realized gain or loss and ineffectiveness portions of those hedges in interest expense. Gains and losses on interest rate derivatives that are not accounted for as cash flow hedges are classified in other income.

Allocation of Income (Loss)

For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see Note 7).

Unit-Based Compensation

We recognize compensation expense for equity awards issued to employees over the vesting period based on the grant-date fair value. The grant-date fair value is determined based on the market price of our Common Units on the grant date, adjusted to reflect the present value of any expected distributions that will not accrue to the employee during the vesting period. The present value of expected service period distributions is computed based on the risk-free interest rate, the expected life of the unit grants and the expected unit distributions based on the most recently declared distributions as of the grant date.

New Accounting Standards

Accounting Standards Codification. On July 1, 2009, the Financial Accounting Standards Board (“FASB”) instituted a new referencing system, which codifies, but does not amend, previously existing nongovernmental U.S. generally accepted accounting principles (“GAAP”). The FASB Accounting Standards Codification (“ASC”) is now the single authoritative source for GAAP. Although the implementation of ASC has no impact on our financial statements, certain references to authoritative GAAP literature within our footnotes have been changed to cite the appropriate content within the ASC.

Noncontrolling Interests. On January 1, 2009, we adopted SFAS 160, now incorporated into ASC 810-10, which established new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, the new standard requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent's equity. The amount of net income attributable to the noncontrolling interest is included in consolidated net income on the face of the income statement. The new standard clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, the new standard requires that a parent recognizes a gain or loss in net income when a subsidiary is deconsolidated. Such gain or loss is measured using the fair value of the noncontrolling equity investment on the deconsolidation date. This standard also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. The adoption of this standard did not have a significant impact on our financial position or results of operations. However, it did result in certain changes to our financial statement presentation, including the change in classification of noncontrolling interest (minority interest) from liabilities to equity on the condensed consolidated balance sheet.

Upon adoption, we reclassified $2.42 billion from minority interest liability to noncontrolling interest as a separate component of equity in our consolidated balance sheet as of December 31, 2008. In addition, we reclassified $304.7 million, $90.1 million and $232.6 million of minority interest expense to net income attributable to noncontrolling interest in our consolidated statements of operations for the year ended December 31, 2008, the four month transition period ended December 31, 2007 and the year ended August 31, 2007. Net income per limited partner unit has not been affected as a result of the adoption of this standard.

Earnings per Unit. On January 1, 2009, we adopted a new methodology for calculating earnings per unit to reflect recently ratified changes to accounting standards. This new standard was originally issued as Emerging Issues Task Force Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships, and is now incorporated into ASC 260-10. Our adoption of this standard did not have an impact on the calculation of ETE’s earnings per unit.

On January 1, 2009, we also adopted FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which is now incorporated into ASC 260-10. This standard clarifies that unvested share-based payment awards constitute participating securities, if such awards include nonforfeitable rights to dividends or dividend equivalents. Consequently, awards that are deemed to be participating securities must be allocated earnings in the computation of earnings per share under the two-class method. Based on unvested unit awards outstanding at the time of adoption, application of this standard did not have a material impact on our computation of earnings per unit.

Business Combinations. On January 1, 2009, we adopted Statement of Financial Accounting Standards No. 141 (Revised 2007), Business Combinations, which is now incorporated into ASC 805. The new standard significantly changes the accounting for business combinations and includes a substantial number of new disclosure requirements. The new standard requires an acquiring entity to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition-date fair value with limited exceptions and changes the accounting treatment for certain specific items, including:

Acquisition costs are generally expensed as incurred;

Noncontrolling interests (previously referred to as "minority interests") are valued at fair value at the acquisition date;

In-process research and development is recorded at fair value as an indefinite-lived intangible asset at the acquisition date;

Restructuring costs associated with a business combination are generally expensed subsequent to the acquisition date; and

Changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date are recorded in income taxes.

Our adoption of this standard did not have an immediate impact on our financial position or results of operations; however, it has impacted the accounting for our business combinations subsequent to adoption.

Derivative Instruments and Hedging Activities. On January 1, 2009, we adopted Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities - An Amendment of FASB Statement No. 133, which is now incorporated into ASC 815. This standard changed the disclosure requirements for derivative instruments and hedging activities, including requirements for qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The standard only affected disclosure requirements; therefore, our adoption did not impact our financial position or results of operations.

Equity Method Investment Accounting. On January 1, 2009, we adopted Emerging Issues Task Force Issue No. 08-6, Equity Method Investment Accounting Considerations, which is now incorporated into ASC 323-10. This standard establishes the requirements for initial measurement of an equity method investment, including the accounting for contingent consideration related to the acquisition of an equity method investment, and also clarifies the accounting for (1) an other-than-temporary impairment of an equity method investment and (2) changes in level of ownership or degree of influence with respect to an equity method investment. Our adoption did not have a material impact on our financial position or results of operations.

Subsequent Events. During 2009, we adopted Statement of Financial Accounting Standards No. 165, Disclosures about Subsequent Events, which is now incorporated into ASC 855. Under this standard, we are required to evaluate subsequent events through the date that our financial statements are issued and also required to disclose the date through which subsequent events are evaluated. The adoption of this standard does not change our current practices with respect to evaluating, recording and disclosing subsequent events; therefore, our adoption of this statement during the second quarter had no impact on our financial position or results of operations.

3.	ACQUISITIONS:

Proposed Transaction

We have agreed to purchase a natural gas gathering company which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale. The purchase price is $150 million in cash, excluding certain adjustments as defined in the purchase agreement, and the acquisition is expected to close in March 2010.

2009

In November 2009, we acquired all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas, in exchange for the issuance of 1,450,076 ETP Common Units having an aggregate market value of approximately $63.3 million on the closing date. In connection with this transaction, we received cash of $41.1 million, assumed total liabilities of $30.5 million, which includes $8.4 million in notes payable and recorded goodwill of $8.7 million. In addition, we acquired ETG in August 2009. See Note 14.

2008

During the year ended December 31, 2008, HOLP and Titan collectively acquired substantially all of the assets of 20 propane businesses. The aggregate purchase price for these acquisitions totaled $96.4 million, which included $76.2 million of cash paid, net of cash acquired, liabilities assumed of $ 8.2 million, 53,893 Common Units issued valued at $2.2 million and debt forgiveness of $9.8 million. The cash paid for acquisitions was financed primarily with ETP’s and HOLP’s Senior Revolving Credit Facilities. We recorded $15.3 million of goodwill in connection with these acquisitions.

Transition Period 2007

Canyon Acquisition

In October 2007, ETP acquired the Canyon Gathering System midstream business of Canyon Gas Resources, LLC from Cantera Resources Holdings, LLC (the “Canyon acquisition”) for $305.2 million in cash, subject to working capital adjustments as defined in the purchase and sale agreement. The purchase price was initially allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition. We completed the purchase price allocation during the third quarter of 2008. The adjustments to the purchase price allocation were not material.

The final allocations of the purchase price are noted below:

Accounts receivable	$	3,613
Inventory		183
Prepaid and other current assets		1,606
Property, plant, and equipment		284,910
Intangibles and other assets		6,351
Goodwill		11,359
Total assets acquired		308,022

Accounts payable		(1,840	)
Customer advances and deposits		(1,030	)
Total liabilities assumed		(2,870	)
Net assets acquired	$	305,152

2007

On November 1, 2006, the Parent Company acquired from Energy Transfer Investments, L.P. (“ETI”, a partnership also controlled by LE GP) the remaining 50% of the Class B Limited Partner interests in ETP GP owned by ETI. The Parent Company recorded this acquisition at ETI’s historical cost of $4.5 million as required under GAAP due to the fact that the Parent Company and ETI are companies under common control. As a result, the Parent Company now owns 100% of the Incentive Distribution Rights of ETP. The acquisition was effected through the issuance of 83,148,900 newly created Parent Company Class C Units and the assumption by the Parent Company of approximately $70.5 million of ETI’s indebtedness. The assumption of this debt represents a non-cash financing activity. The Class C Units were recorded at the net value of the debt assumption (accounted for as a distribution to ETI) and the value of the ETP GP Class B Units acquired, a net amount of $66.0 million. The Class C Units had essentially the same voting rights and rights to distributions as the Common Units and Class B Units. The Class C Units converted into Common Units upon approval by the ETE Common Unitholders on February 22, 2007.

Also on November 1, 2006, the Parent Company acquired additional limited partner interests in ETP (Class G Units, which subsequently converted to Common Units on May 1, 2007, see Note 7) which increased the Parent Company’s aggregate ownership in ETP’s limited partner interests to approximately 46%.

On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), ETP acquired the member interests in CCE Holdings, LLC (“CCEH”) from GE and certain other investors for $1.00 billion. ETP financed a portion of the CCEH purchase price with the proceeds from its issuance of 26,086,957 Class G Units to the Parent Company simultaneous with the closing on November 1, 2006. The member interests acquired represented a 50% ownership in CCEH. On December 1, 2006, in a second and related transaction, CCEH redeemed ETP’s 50% ownership interest in CCEH in exchange for 100% ownership of Transwestern, which owns the Transwestern pipeline. Following the final step, Transwestern became a new operating subsidiary and formed the interstate transportation segment of ETP.

The total acquisition cost for Transwestern, net of cash acquired, was as follows:

Basis of investment in CCEH at November 30, 2006	$	956,348
Distributions received on December 1, 2006		(6,217	)
Fair value of short-term debt assumed		13,000
Fair value of long-term debt assumed		519,377
Other assumed long-term indebtedness		10,096
Current liabilities assumed		35,781
Cash acquired		(3,386	)
Acquisition costs incurred		11,696
Total	$	1,536,695

In September 2006, ETP acquired two small natural gas gathering systems in east and north Texas for an aggregate purchase price of approximately $30.6 million in cash. The purchase and sale agreement for the gathering system in north Texas also had a contingent payment not to exceed $25.0 million to be determined eighteen months from the closing date. These systems provide us with additional capacity in the Barnett Shale and in the Travis Peak area of east Texas and are included in our midstream operating segment. The cash paid for this acquisition was financed primarily from advances under the previously existing credit facility. In March 2008, a contingent payment of $8.7 million was recorded as an adjustment to goodwill in the midstream segment.

In December 2006, ETP purchased a natural gas gathering system in north Texas for $32.0 million in cash. The purchase and sale agreement for the gathering system in north Texas also had a contingent payment not to exceed $21.0 million to be determined two years after the closing date. In December 2008, it was determined that a contingency payment would not be required. The gathering system consists of approximately 36 miles of pipeline and has an estimated capacity of 70 MMcf/d. We expect the gathering system will allow us to continue expanding in the Barnett Shale area of north Texas. The cash paid for this acquisition was financed primarily from advances under the previously existing credit facility.

During the fiscal year ended August 31, 2007, HOLP and Titan collectively acquired substantially all of the assets of five propane businesses. The aggregate purchase price for these acquisitions totaled $17.6 million, which included $15.5 million of cash paid, net of cash acquired, and liabilities assumed of $2.1 million. The cash paid for acquisitions was financed primarily with ETP’s and HOLP’s Senior Revolving Credit Facilities.

Except for the acquisition of the interests in ETP GP, the purchase of Class G Units from ETP and the 50% member interests in CCEH, the acquisitions discussed above were accounted for under the purchase method of accounting and the purchase prices were allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition. The acquisition of the 50% member interest in CCEH was accounted for under the equity method of accounting in accordance with APB Opinion No. 18, through November 30, 2006. The acquisition of 100% of Transwestern has been accounted for under the purchase method of accounting since the acquisition on December 1, 2006. The acquisition of the interests in ETP GP was accounted for on the basis of historical costs, as discussed above. The purchase of Class G Units from ETP was accounted for as described in Note 7.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for the fiscal year 2007 acquisitions described above, net of cash acquired:

	Intrastate Transportation and Storage and Midstream Acquisitions (Aggregated)			Transwestern Acquisition			Propane Acquisitions (Aggregated)
Accounts receivable	$	-		$	20,062		$	1,111
Inventory		-			895			414
Prepaid and other current assets		-			11,842			57
Investment in unconsolidated affiliate		(503	)		-			-
Property, plant, and equipment		50,916			1,254,968			8,035
Intangibles and other assets		23,015			141,378			3,808
Goodwill		-			107,550			4,167
Total assets acquired		73,428			1,536,695			17,592

Accounts payable		-			(1,932	)		(381	)
Customer advances and deposits		-			(700	)		(254	)
Accrued and other current liabilities		(292	)		(33,149	)		(170	)
Short-term debt (paid in December 2006)		-			(13,000	)		-
Long-term debt		-			(519,377	)		(1,309	)
Other long-term obligations		-			(10,096	)		-
Total liabilities assumed		(292	)		(578,254	)		(2,114	)
Net assets acquired	$	73,136		$	958,441		$	15,478

The purchase price for the acquisitions was initially allocated based on the estimated fair value of the assets acquired and liabilities assumed. The Transwestern allocation was based on the preliminary results of independent appraisals. The purchase price allocations were completed during the first quarter of 2008. The final allocation adjustments were not significant.

Included in the property, plant and equipment associated with the Transwestern acquisition is an aggregate plant acquisition adjustment of $446.2 million, which represents costs allocated to Transwestern’s transmission plant. This amount has not been included in the determination of tariff rates Transwestern charges to its regulated customers. The unamortized balance of this adjustment was $419.6 million at December 31, 2008 and is being amortized over 35 years, the composite weighted average estimated remaining life of Transwestern’s assets as of the acquisition date.

Regulatory assets, included in intangible and other assets on the consolidated balance sheet, established in the Transwestern purchase price allocation consist of the following:

Accumulated reserve adjustment	$	42,132
AFUDC gross-up		9,280
Environmental reserves		6,623
South Georgia deferred tax receivable		2,593
Cash Balance Plan		9,329
Total Regulatory Assets acquired	$	69,957

All of Transwestern’s regulatory assets are considered probable of recovery in rates.

We recorded the following intangible assets and goodwill in conjunction with the fiscal year 2007 acquisitions described above:

	Intrastate Transportation and Storage and Midstream Acquisitions (Aggregated)		Transwestern Acquisition		Propane Acquisitions (Aggregated)
Intangible assets:
Contract rights and customer lists (6 to 15 years)	$	23,015	$	47,582	$	-
Financing costs (7 to 9 years)		-		13,410		-
Other		-		-		3,808
Total intangible assets		23,015		60,992		3,808

Goodwill		-		107,550		4,167
Total intangible assets and goodwill acquired	$	23,015	$	168,542	$	7,975

Goodwill was warranted because these acquisitions enhance our current operations, and certain acquisitions are expected to reduce costs through synergies with existing operations. We expect all of the goodwill acquired to be tax deductible. We do not believe that the acquired intangible assets have any significant residual value at the end of their useful life.

4.	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 in the latter part of 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 Quitman 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. The pipeline project is expected to be in service by the end of 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.

Capital Contributions to Affiliates

During the year ended December 31, 2009, we contributed $664.5 million to MEP. FEP’s capital expenditures are being funded under a credit facility. All of our contributions to FEP were reimbursed to us in 2009, including $9.0 million that we contributed in 2008.

Summarized Financial Information

The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, MEP and FEP (on a 100% basis):

	December 31, 2009		December 31, 2008
Current assets	$	33,794	$	9,953
Property, plant and equipment, net		2,576,031		1,012,006
Other assets		19,658		-
Total assets	$	2,629,483	$	1,021,959

Current liabilities	$	105,951	$	163,379
Non-current liabilities		1,198,882		840,580
Equity		1,324,650		18,000
Total liabilities and equity	$	2,629,483	$	1,021,959

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007

Revenue	$	98,593	$	-	$	-	$	-
Operating income		47,818		-		-		-
Net income		36,555		1,057		-		-

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

5.	INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the number of unvested ETE Incentive Units granted. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP that would have resulted assuming the incremental units related to ETP’s equity incentive plans had been issued during the respective periods. Such units have been determined based on the treasury stock method.

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

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007
Basic Net Income per Limited Partner Unit:
Limited Partner’s interest in net income	$	441,103		$	373,883		$	92,390		$	318,312

Weighted average limited partner units		222,898,203			222,829,956			222,829,916			204,578,719

Basic net income per limited partner unit	$	1.98		$	1.68		$	0.41		$	1.56

Diluted Net Income per Limited Partner Unit:
Limited Partner’s interest in net income	$	441,103		$	373,883		$	92,390		$	318,312
Dilutive effect of Unit Grants		(410	)		(349	)		(218	)		(376	)
Diluted net income available to limited partners	$	440,693		$	373,534		$	92,172		$	317,936

Weighted average limited partner units		222,898,203			222,829,956			222,829,916			204,578,719

Diluted net income per limited partner unit	$	1.98		$	1.68		$	0.41		$	1.55

6.	DEBT OBLIGATIONS:

Our debt obligations consist of the following:

	December 31, 2009			December 31, 2008
ETP Senior Notes:
5.95% Senior Notes, due February 1, 2015	$	750,000		$	750,000		Payable upon maturity. Interest is paid semi-annually.
5.65% Senior Notes, due August 1, 2012		400,000			400,000		Payable upon maturity. Interest is paid semi-annually.
6.125% Senior Notes, due February 15, 2017		400,000			400,000		Payable upon maturity. Interest is paid semi-annually.
6.625% Senior Notes, due October 15, 2036		400,000			400,000		Payable upon maturity. Interest is paid semi-annually.
6.0% Senior Notes, due July 1, 2013		350,000			350,000		Payable upon maturity. Interest is paid semi-annually.
6.7% Senior Notes, due July 1, 2018		600,000			600,000		Payable upon maturity. Interest is paid semi-annually.
7.5% Senior Notes, due July 1, 2038		550,000			550,000		Payable upon maturity. Interest is paid semi-annually.
9.7% Senior Notes due March 15, 2019		600,000			600,000		Put option on March 15, 2012. Payable upon maturity. Interest is paid semi-annually.
8.5% Senior Notes due April 15, 2014		350,000			-		Payable upon maturity. Interest is paid semi-annually.
9.0% Senior Notes due April 15, 2019		650,000			-		Payable upon maturity. Interest is paid semi-annually.

Transwestern Senior Unsecured Notes:
5.39% Senior Unsecured Notes, due November 17, 2014		88,000			88,000		Payable upon maturity. Interest is paid semi-annually.
5.54% Senior Unsecured Notes, due November 17, 2016		125,000			125,000		Payable upon maturity. Interest is paid semi-annually.
5.64% Senior Unsecured Notes, due May 24, 2017		82,000			82,000		Payable upon maturity. Interest is paid semi-annually.
5.89% Senior Unsecured Notes, due May 24, 2022		150,000			150,000		Payable upon maturity. Interest is paid semi-annually.
6.16% Senior Unsecured Notes, due May 24, 2037		75,000			75,000		Payable upon maturity. Interest is paid semi-annually.
5.36% Senior Unsecured Notes, due December 9, 2020		175,000			-		Payable upon maturity. Interest is paid semi-annually.
5.66% Senior Unsecured Notes, due December 9, 2024		175,000			-		Payable upon maturity. Interest is paid semi-annually.

HOLP Senior Secured Notes:
8.55% Senior Secured Notes		24,000			36,000		Annual payments of $12,000 due each June 30 through 2011. Interest is paid semi-annually.
Medium Term Note Program:
7.17% Series A Senior Secured Notes		-			2,400		Matured in November 2009.
7.26% Series B Senior Secured Notes		6,000			8,000		Annual payments of $2,000 due each November 19 through 2012. Interest is paid semi-annually.
Senior Secured Promissory Notes:
8.55% Series B Senior Secured Notes		4,571			9,142		Annual payments of $4,571 due each August 15 through 2010. Interest is paid quarterly.
8.59% Series C Senior Secured Notes		5,750			11,500		Annual payments of $5,750 due each August 15 through 2010. Interest is paid quarterly.
8.67% Series D Senior Secured Notes		33,100			45,550		Annual payments of $7,700 due August 15, 2010, $12,450 due August 15, 2011, and $12,950 due August 15, 2012. Interest is paid quarterly.
8.75% Series E Senior Secured Notes		6,000			7,000		Annual payments of $1,000 due each August 15 through 2015. Interest is paid quarterly.
8.87% Series F Senior Secured Notes		40,000			40,000		Annual payments of $3,636 due each August 15, 2010 through 2020. Interest is paid quarterly.
7.89% Series H Senior Secured Notes		5,091			5,818		Annual payments of $727 due each May 15 through 2016. Interest is paid quarterly.
7.99% Series I Senior Secured Notes		16,000			16,000		One payment due May 15, 2013. Interest is paid quarterly.
Revolving Credit Facilities and Term Loans:
ETE Senior Secured Revolving Credit Facility		123,951			121,642		See terms below under “Parent Company Credit Facilities”.
ETE Senior Secured Term Loan		1,450,000			1,450,000		See terms below under “Parent Company Credit Facilities”.
ETP Revolving Credit Facility		150,000			902,000		See terms below under "ETP Credit Facility".
HOLP Fourth Amended and Restated Senior Revolving Credit Facility		10,000			10,000		See terms below under "HOLP Credit Facility".

Other Long-Term Debt:
Notes payable on noncompete agreements with interest imputed at rates averaging 8.06% and 7.91% for December 31, 2009 and 2008, respectively		7,898			11,249		Due in installments through 2014.
Other		2,390			2,765		Due in installments through 2024.
Unamortized discounts		(12,829	)		(13,477	)
		7,791,922			7,235,589
Current maturities		(40,924	)		(45,232	)
	$	7,750,998		$	7,190,357

Future maturities of long-term debt for each of the next five years and thereafter are as follows:

2010	$	40,924
2011		168,558
2012		2,022,881
2013		372,569
2014		443,519
Thereafter		4,743,471
	$	7,791,922

ETP Senior Notes

The ETP Senior Notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP Senior Notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP Senior Notes. Interest on the ETP Senior Notes is paid semi-annually.

The ETP Senior Notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP Senior Notes is not guaranteed by us, ETP or any of ETP’s subsidiaries. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ours, ETP’s or its subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of ETP’s existing and future subsidiaries.

In April 2009, we completed a public offering of $350.0 million aggregate principal amount of 8.5% Senior Notes due 2014 and $650.0 million aggregate principal amount of 9.0% Senior Notes due 2019 (collectively the “2009 ETP Notes”). The offering of the 2009 ETP Notes closed on April 7, 2009 and we used net proceeds of approximately $993.6 million to repay borrowings under the ETP Credit Facility and for general partnership purposes. Interest will be paid semi-annually.

Transwestern Senior Unsecured Notes

Transwestern’s long-term debt consists of $213.0 million remaining principal amount of notes assumed in connection with the Transwestern acquisition, $307.0 million aggregate principal amount of notes issued in May 2007, and $350.0 million aggregate principal amount of notes issued in December 2009. The proceeds from the notes issued in December 2009 were used by Transwestern to repay amounts under an intercompany loan agreement. No principal payments are required under any of the Transwestern notes prior to their respective maturity dates. The Transwestern notes rank pari passu with Transwestern’s other unsecured debt. The Transwestern notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. Interest is paid semi-annually.

Transwestern’s debt agreements contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.

HOLP Senior Secured Notes

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes (collectively, the “HOLP Notes”).

Revolving Credit Facilities

Parent Company Facilities

The Parent Company has a $1.45 billion Term Loan Facility and 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 Parent Company Revolving Credit Facility includes a Swingline loan option with a maximum borrowing of $10.0 million and a daily rate based on LIBOR.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of December 31, 2009 was $1.57 billion. The total amount available under the Parent Company’s debt facilities as of December 31, 2009 was $376.0 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.

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 III or 0.375%. 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 December 31, 2009, 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 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 December 31, 2009, there was a balance outstanding in the ETP Credit Facility of $150.0 million in revolving credit loans and approximately $62.2 million in letters of credit. The weighted average interest rate on the total amount outstanding at December 31, 2009 was 0.78%. The total amount available under the ETP Credit Facility, as of December 31, 2009, which is reduced by any letters of credit, was approximately $1.79 billion. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt.

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 (total book value as of December 31, 2009 of approximately $1.2 billion). At December 31, 2009, there was $10.0 million outstanding in revolving credit loans and outstanding letters of credit of $1.0 million. The amount available for borrowing as of December 31, 2009 was $64.0 million.

Covenants Related to Our Credit Agreements

The agreements related to the ETP Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The agreements and indentures related to each of the Parent Company Revolving Credit Facility and Senior Secured Term Loan Facility and ETP’s and the Operating Companies’ HOLP Notes and the HOLP Credit Facility contain customary restrictive covenants applicable to the Parent Company, ETP and the Operating Companies, including the maintenance of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens as described in further detail below.

The Parent Company Revolving Credit Facility and Senior Secured Term Loan Facility contain financial covenants as follows:

Maximum Leverage Ratio – Consolidated Funded Debt of the Parent Company (as defined) to Consolidated EBITDA (as defined in the agreements) of the Parent Company of not more than 4.50 to 1.00, with a permitted increase to 5.00 to 1.00 during a specified acquisition period extending for two fiscal quarters following the close of a specified acquisition

Maximum Consolidated Leverage Ratio – Consolidated Funded Debt of the Parent Company and ETP to Consolidated EBITDA of ETP of not more than 5.50 to 1.00

Interest Coverage Ratio may not be less than 3.00 to 1.00

Value to Loan Ratio may not be less than 2.00 to 1.00

The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries, ability to, among other things:

incur indebtedness;

grant liens;

enter into mergers;

dispose of assets;

make certain investments;

make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);

engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;

engage in transactions with affiliates;

enter into restrictive agreements; and

enter into speculative hedging contracts.

The credit agreement related to the ETP Credit Facility also contains a financial covenant that provides that on each date ETP makes a distribution, the leverage ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified acquisition period, as defined in the ETP Credit Facility. This financial covenant could therefore restrict ETP’s ability to make cash distributions to its Unitholders, its general partner and the holder of its incentive distribution rights.

The agreements related to the HOLP Notes and the HOLP Credit Facility contain customary restrictive covenants applicable to HOLP, including the maintenance of various financial and leverage covenants and limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens. The financial covenants require HOLP to maintain ratios of Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the agreements related to the HOLP Notes and HOLP Credit Facility) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the agreements related to the HOLP Notes and HOLP Credit Facility) of not less than 2.25 to 1. These debt agreements also provide that HOLP may declare, make, or incur a liability to make restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed the amount of Available Cash (as defined in the agreements related to the HOLP Notes and HOLP Credit Facility) with respect to the immediately preceding quarter (which amount is required to reflect a reserve equal to 50% of the interest to be paid on the HOLP Notes during the last quarter and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the HOLP Notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates), (b) no default or event of default exists before such restricted payments, and (c) the amounts of HOLP’s restricted payment is not disproportionately greater than the payment amount from ETC OLP utilized to fund payment obligations of ETP and its general partner with respect to ETP’s Common Units.

Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and the note agreements related to the HOLP Notes could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.

We are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2009.

7.	PARTNERS’ CAPITAL:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Act of 1934 and are listed for trading on the New York Stock Exchange (“NYSE”). Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”

As of December 31, 2009, there were issued and outstanding 222,898,248 Common Units representing an aggregate 99.69% limited partner interest in the Partnership.

Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

In connection with our initial public offering in February 2006, we issued Class B Units to our management, and all of the Class B Units were converted to ETE Common Units in March 2007. In November 2006, we issued Class C Units to acquire limited partner interest in ETP GP, and in February 2007, all of the Class C Units were converted to ETE Common Units.

Common Units

The change in Common Units is as follows:

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007
Number of Units, beginning of period		222,829,956		222,829,956		222,828,332		124,360,520
Issuance of restricted Common Units under long-term incentive plan		68,292		-		1,624		1,948
Issuance of Common Units		-		-		-		12,795,394
Conversion of Class B Units to Common Units		-		-		-		2,521,570
Conversion of Class C Units to Common Units		-		-		-		83,148,900
Number of Units, end of period		222,898,248		222,829,956		222,829,956		222,828,332

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. The capital transactions are reflected in the Partnership’s consolidated balance sheets as an increase in partners’ capital. 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 periods presented.

On November 1, 2006, the Parent Company purchased 26,086,957 Class G Units representing limited partnership interests in ETP. The price per unit paid for each of the Common Units was equal to $46.00 per unit, based upon a market discount from the NYSE closing price of the ETP’s Common Units on October 31, 2006 of $48.94. ETP used a portion of the proceeds to purchase interests in CCEH (see Note 3). On May 1, 2007, the Unitholders of ETP approved the conversion of the Class G Units to Common Units and all the outstanding ETP Class G Units converted to ETP Common Units on a one-for-one basis on such date. The Parent Company recorded the premium of $451.2 million (the difference between the Parent Company’s share of the underlying book value in ETP before and after the purchase of the Class G Units) as a reduction of the Parent Company’s limited partners’ capital with a corresponding increase in minority interest.

The following table summarizes ETP’s public offerings of ETP Common Units:

Date	Number of Common Units (1)		Price per Unit		Net Proceeds		Use of Proceeds

December 2007 (2)		5,750,000	$	48.81	$	269.4		(3)
July 2008		8,912,500		39.45		337.5		(4)
January 2009		6,900,000		34.05		225.4		(4)
April 2009		9,775,000		37.55		352.4		(5)
October 2009		6,900,000		41.27		276.0		(4)
January 2010		9,775,000		44.72		423.6		(4)(5)

___________

(1)

Number of Common Units includes the exercise of the overallotment options by the underwriters.

(2)

Amounts include the exercise of the overallotment option by the underwriters in January 2008.

(3)

Proceeds were used to repay amounts outstanding under ETP's prior term loan facility.

(4)

Proceeds were used to repay amounts outstanding under the ETP Credit Facility.

(5)

Proceeds were used to fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.

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 offering price 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 2009, ETP issued 2,079,593 ETP Common Units pursuant to this agreement 1,891,691 of which have been settled as of December 31, 2009. The proceeds of approximately $81.5 million, net of commissions, were used to repay amounts outstanding under the ETP Credit Facility.

As a result of ETP’s issuance of ETP Common Units, we have recognized increases in partner’s capital of $97.0 million and $48.8 million for the years ended December 31, 2009 and 2008, respectively, and $48.9 million for the four months ended December 31, 2007.

Contributions to Subsidiary

The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. In order to maintain its general partner interest in ETP, ETP GP has previously been required to make contributions to ETP each time ETP issues limited partner interests for cash or in connection with acquisitions. These contributions are generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP. ETP GP was required to contribute approximately $12.3 million and $8.0 million for the years ended December 31, 2009 and 2008, $5.0 million for the four months ended December 31, 2007, and $24.5 million for the year ended August 31, 2007, respectively. As of December 31, 2009, ETP GP has a contribution payable to ETP of $8.9 million.

In July 2009, ETP amended and restated its partnership agreement, and as a result, ETP GP is no longer required to make corresponding contributions to maintain its general partner interest in ETP.

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. We currently have no independent operations outside of our interests in ETP.

Our only cash-generating assets currently consist of distributions from ETP related to the following limited and general partner interests, including incentive distribution rights in ETP:

ETE’s ownership of the general partner interest in ETP, which it holds through its ownership interests in ETP GP.

62,500,797 ETP Common Units, which ETE holds directly, representing approximately 35% of the total outstanding ETP Common Units as of December 31, 2009, and

100% of the incentive distribution rights in ETP, which ETE holds through its ownership interests in ETP GP and which entitle it to receive specified percentages of the cash distributed by ETP as ETP’s per unit distribution increases. The Parent Company’s incentive distribution rights entitle it to receive incentive distributions to the extent that quarterly distributions to ETP’s Unitholders exceed $0.275 per unit ($1.10 per unit on an annualized basis). These incentive distributions entitle the Parent Company to increasing percentages of ETP’s cash distributions based upon exceeding incentive distribution thresholds specified in ETP’s Partnership Agreement, which incentive distribution rights entitle the Parent Company to receive 48% of ETP’s cash distributions in excess of $0.4125 per unit. At ETP’s current distribution levels, the Parent Company is entitled to receive cash distributions at the highest incentive distribution level of 48% with respect to ETP’s distributions in excess of $0.4125 per unit.

Our distributions declared during the years ended December 31, 2009 and 2008, the four months ended December 31, 2007 and the year ended August 31, 2007 are summarized as follows:

	Record Date	Payment Date	Amount per Unit
Calendar Year Ended December 31, 2009	November 9, 2009	November 19, 2009	$	0.5350
	August 7, 2009	August 19, 2009		0.5350
	May 8, 2009	May 19, 2009		0.5250
	February 6, 2009	February 19, 2009		0.5100

Calendar Year Ended December 31, 2008	November 10, 2008	November 19, 2008	$	0.4800
	August 7, 2008	August 19, 2008		0.4800
	May 5, 2008	May 19, 2008		0.4400
	February 1, 2008 (1)	February 19, 2008		0.5500

Transition Period Ended December 31, 2007	October 5, 2007	October 19, 2007	$	0.3900

Fiscal Year Ended August 31, 2007	July 2, 2007	July 19, 2007	$	0.3725
	April 9, 2007	April 16, 2007		0.3560
	January 4, 2007	January 19, 2007		0.3400
	October 5, 2006	October 19, 2006		0.3125

(1)

One-time four month distribution – On January 18, 2008, our Board of Directors approved the management recommendation for a one-time four-month distribution for our Unitholders to complete the conversion to a calendar year end from the previous August 31 fiscal year end. ETE’s distribution amount related to the four months ended December 31, 2007 was $0.55 per Common Unit, representing a distribution of $0.41 per unit for the three-month period and $0.14 per unit for the additional month.

The total amount of distributions we have declared is as follows (all from Available Cash from our operating surplus and are shown in the period to which they relate):

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007
Limited Partners -
Common Units	$	475,911	$	425,640	$	122,556	$	294,175
Class B Units		-		-		-		857
Class C Units		-		-		-		28,261

General Partner		1,478		1,322		381		1,009
Total distributions declared	$	477,389	$	426,962	$	122,937	$	324,302

On January 28, 2010, the Parent Company declared a cash distribution for the fourth quarter ended December 31, 2009 of $0.54 per Common Unit, or $2.16 annualized. We paid this distribution on February 19, 2010 to Unitholders of record at the close of business on February 8, 2010.

ETP’s Quarterly Distribution of Available Cash

ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.

ETP’s distributions declared during the periods presented below are summarized as follows:

	Record Date	Payment Date	Amount per Unit
Calendar Year Ended December 31, 2009	November 9, 2009	November 16, 2009	$	0.89375
	August 7, 2009	August 14, 2009		0.89375
	May 8, 2009	May 15, 2009		0.89375
	February 6, 2009	February 13, 2009		0.89375

Calendar Year Ended December 31, 2008	November 10, 2008	November 14, 2008	$	0.89375
	August 7, 2008	August 14, 2008		0.89375
	May 5, 2008	May 15, 2008		0.86875
	February 1, 2008 (1)	February 14, 2008		1.12500

Transition Period Ended December 31, 2007	October 5, 2007	October 15, 2007	$	0.82500

Fiscal Year Ended August 31, 2007	July 2, 2007	July 16, 2007	$	0.80625
	April 6, 2007	April 13, 2007		0.78750
	January 4, 2007	January 15, 2007		0.76875
	October 5, 2006	October 16, 2006		0.75000

(1)

One-time four month distribution – On January 18, 2008 ETP’s Board of Directors approved the management recommendation for a one-time four-month distribution for ETP Unitholders to complete the conversion to a calendar year end from the previous August 31 fiscal year end. ETP’s distribution amount related to the four months ended December 31, 2007 was $1.125 per Common Unit, representing a distribution of $0.84375 per unit for the three-month period and $0.28125 per unit for the additional month.

The total amount of distributions the Parent Company received from ETP relating to its limited partner interests, general partner interests and incentive distribution rights of ETP are as follows (shown in the period to which they relate):

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007

Limited Partners Interests	$	223,440	$	221,878	$	70,313	$	199,221
General Partner Interest		19,505		17,322		5,110		13,705
Incentive Distribution Rights		350,486		298,575		85,775		222,353
Total distributions received from ETP	$	593,431	$	537,775	$	161,198	$	435,279

The total amounts of ETP distributions declared during the periods presented in the consolidated financial statements are as follows (all from Available Cash from ETP’s operating surplus and are shown in the period to which they relate):

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007
Limited Partners -
Common Units	$	629,263	$	537,731	$	160,672	$	396,095
Class E Units		12,484		12,484		3,121		12,484
Class G Units		-		-		-		40,598

General Partner Interest		19,505		17,322		5,110		13,705
Incentive Distribution Rights		350,486		298,575		85,775		222,353
	$	1,011,738	$	866,112	$	254,678	$	685,235

Upon their conversion to ETP Common Units, all the ETP Class G Units ceased to have the right to participate in ETP distributions of available cash from operating surplus as itemized above.

On January 28, 2010, ETP declared a cash distribution for the fourth quarter ended December 31, 2009 of $0.89375 per Common Unit, or $3.575 annualized. ETP paid this distribution on February 15, 2010 to Unitholders of record at the close of business on February 8, 2010.

Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:

	December 31, 2009			December 31, 2008
Net gain on commodity related hedges	$	1,991		$	8,735
Net loss on interest rate hedges		(56,210	)		(68,896	)
Unrealized gains (losses) on available-for-sale securities		4,941			(5,983	)
Noncontrolling interest		(4,350	)		(1,681	)
Total AOCI, net of tax	$	(53,628	)	$	(67,825	)

8.	UNIT-BASED COMPENSATION PLANS:

We recognized non-cash unit-based compensation expense related to the unit-based compensation plans of ETP and ETE of $24.6 million and $24.3 million for the years ended December 31, 2009 and 2008, $8.1 million for the four months ended December 31, 2007, and $10.5 million for the year ended August 31, 2007, respectively.

ETE Long-Term Incentive Plan

Concurrently with the IPO during the second quarter of fiscal year 2006, 2,521,570 Class B Units were issued to McReynolds Equity Partners, L.P., the general partner of which is owned and controlled by John W. McReynolds. On March 27, 2007, the Class B Units were converted to Common Units.

In addition, the Board of Directors or the Compensation Committee of the board of directors of the Partnership’s general partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 3,000,000 units, excluding the Class B Units discussed above. As of December 31, 2009, 2,887,136 units remain available to be awarded under the plan.

During 2009 and 2008, the Compensation Committee granted a total of 41,000 and 65,000 ETE units with grant date fair values of $16.64 and $30.76 per unit, respectively, to employees with vesting over a five-year period at 20% per year. These awards include rights to distributions paid on unvested units.

On December 22, 2006, the Compensation Committee voted to award each ETE Director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (“Director Participant”), who is then in office and, automatically on the first day of the fiscal year thereafter, an award of Units equal to $15 thousand divided by the fair market value of ETE Common Units on such date (“Annual Director’s Grant”). Each award to a Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, all awards to a Director Participant shall become fully vested upon a change in control, as defined by the 2004 Unit Plan. During 2009, a total of 14,192 ETE units vested, with a total fair value of $0.4 million. As of December 31, 2009, a total of 96,836 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of $1.9 million in compensation over a weighted average period of 2.7 years.

ETP Unit-Based Compensation Plans

ETP has issued equity awards to employees and directors under the following plans:

2008 Long-Term Incentive Plan. On December 16, 2008, ETP Unitholders approved the ETP 2008 Long-Term Incentive Plan (the “ETP 2008 Incentive Plan”), which provides for awards of options to purchase ETP Common Units, awards of restricted units, awards of phantom units, awards of Common Units, awards of distribution equivalent rights (“DERs”), awards of Common Unit appreciation rights, and other unit-based awards to employees of ETP, ETP GP, ETP LLC, a subsidiary or their affiliates, and members of ETP LLC’s board of directors, which we refer to as the board of directors. Up to 5,000,000 ETP Common Units may be granted as awards under the ETP 2008 Incentive Plan, with such amount subject to adjustment as provided for under the terms of the ETP 2008 Incentive Plan. The ETP 2008 Incentive Plan is effective until December 16, 2018 or, if earlier, the time which all available units under the ETP 2008 Incentive Plan have been issued to participants or the time of termination of the plan by the board of directors. As of December 31, 2009, a total of 4,213,111 ETP Common Units remain available to be awarded under the ETP 2008 Incentive Plan.

2004 Unit Plan. ETP’s Amended and Restated 2004 Unit Award Plan (the “ETP 2004 Unit Plan”) provides for awards of up to 1,800,000 ETP Common Units and other rights to its employees, officers and directors. Any awards that are forfeited or which expire for any reason or any units, which are not used in the settlement of an award, will be available for grant under the ETP 2004 Unit Plan. As of December 31, 2009, 5,578 ETP Common Units were available for future grants under the ETP 2004 Unit Plan.

ETP Employee Grants

Prior to December 2007, substantially all of the awards granted to employees required the achievement of performance objectives in order for the awards to become vested. The expected life of each unit award subject to the achievement of performance objectives is assumed to be the minimum vesting period under the performance objectives of such unit award. Generally, each award was structured to provide that, if the performance objectives related to such award are achieved, one-third of the units subject to such award will vest each year over a three-year period with 100% of such one-third vesting if the total return for the ETP units for such year is in the top quartile as compared to a peer group of energy-related publicly traded limited partnerships determined by the Compensation Committee, 65% of such one-third vesting if the total return of the ETP units for such year is in the second quartile as compared to such peer group companies, and 25% of such one-third vesting if the total return of the ETP units for such year is in the third quartile as compared to such peer group companies. Total return is defined as the sum of the per unit price appreciation in the market price of the ETP units for the year plus the aggregate per unit cash distributions received for the year. Non-cash compensation expense is recorded for these ETP awards based upon the total awards granted over the required service period that are expected to vest based on the estimated level of achievement of performance objectives. As circumstances change, cumulative adjustments of previously-recognized compensation expense are recorded.

In October 2008, the Compensation Committee determined that, of the unit awards subject to the achievement of performance objectives, 25% of the ETP Common Units subject to such awards eligible to vest on September 1, 2007 became vested and 75% of the awards were forfeited based on ETP’s performance for the twelve-month period ended August 31, 2008. In October 2008, the Compensation Committee approved a special grant of the new unit awards that entitled each holder to receive a number of ETP Common Units equal to the number of ETP Common Units forfeited as of September 1, 2007, which new unit awards became fully vested on October 15, 2008. These Compensation Committee actions affected all ETP employee unit awards including unit awards granted to ETP’s executive officers.

Commencing in December 2007, ETP has also granted restricted unit awards to employees that vest over a specified time period, with vesting based on continued employment as of each applicable vesting date without regard to the satisfaction of any performance objectives. Upon vesting, ETP Common Units are issued. The unit awards under ETP’s equity incentive plans generally require the continued employment of the recipient during the vesting period; however, the Compensation Committee has complete discretion to accelerate the vesting of unvested unit awards.

In 2008 and 2009, the Compensation Committee approved the grant of new unit awards, which vest over a five-year period at 20% per year, subject to continued employment through each specified vesting date. These unit awards entitle the recipients of the unit awards to receive, with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per ETP Common Unit made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.”

Prior to 2008 and 2009, units were generally awarded without distribution equivalent rights. For such awards, ETP calculated the grant-date fair value based on the market value of the underlying units, reduced by the present value of the distributions expected to be paid on the units during the requisite service period. The present value of expected service period distributions is computed based on the risk-free interest rate, the expected life of the unit grants and the distribution yield at that time.

Director Grants

Under ETP’s equity incentive plans, ETP’s non-employee directors each receive unvested ETP Common Units with a grant-date fair value of $50,000 each year. These non-employee director grants vest ratably over three years and do not entitle the holders to receive distributions during the vesting period.

Award Activity

The following table shows the activity of the ETP awards granted to employees and non-employee directors:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 2008		1,372,568		$	36.83
Awards granted		763,190			43.56
Awards vested		(336,386	)		36.02
Awards forfeited		(108,780	)		39.17
Unvested awards as of December 31, 2009		1,690,592			39.88

The balance above for unvested awards as of December 31, 2008 includes 150,852 unit awards with a grant-date fair value of $43.96 per unit, which were granted prior to 2008 and were subject to a performance condition, as described above. These remaining performance awards vested in 2009, and none of the unvested unit awards outstanding as of December 31, 2009 contain performance conditions.

During the years ended December 31, 2009 and 2008, the four months ended December 31, 2007 and the year ended August 31, 2007, the weighted average grant-date fair value per unit award granted was $43.56, $33.86, $42.46 and $43.73, respectively. The total fair value of awards vested was $14.7 million, $14.6 million, $3.3 million and $7.9 million, respectively based on the market price of ETP Common Units as of the vesting date. As of December 31, 2009, a total of 1,690,592 unit awards remain unvested, for which ETP expects to recognize a total of $50.9 million in compensation expense over a weighted average period of 1.9 years.

Related Party Awards

McReynolds Energy Partners, L.P., the general partner of which is owned and controlled by an ETE officer, awarded to certain officers of ETP certain rights related to units of ETE previously issued by ETE to such officer. These rights include the economic benefits of ownership of these ETE units based on a five year vesting schedule whereby the officer will vest in the ETE units at a rate of 20% per year. As these ETE units are conveyed to the recipients of these awards upon vesting from a partnership that is not owned or managed by ETE or ETP, none of the costs related to such awards are paid by ETP or ETE unless this partnership defaults under its obligations pursuant to these unit awards. As these units were outstanding prior to these awards, these awards do not represent an increase in the number of outstanding units of either ETP or ETE and are not dilutive to cash distributions per unit with respect to either ETP or ETE.

During the years ended December 31, 2008 and August 31, 2007, unvested rights related to 450,000 ETE common units and 675,000 ETE common units, respectively, with aggregate grant-date fair values of $10.3 million and $23.5 million, respectively, were awarded to ETP officers. During the year ended December 31, 2008, unvested rights related to 240,000 ETE common units were forfeited. During the years ended December 31, 2009 and 2008 and the four months ended December 31, 2007, ETP officers vested in rights related to 165,000 ETE common units, 135,000 ETE common units, and 55,000 ETE common units, respectively, with aggregate fair values upon vesting of $4.6 million, $3.5 million, and $1.9 million, respectively.

ETP is recognizing non-cash compensation expense over the vesting period based on the grant-date fair value of the ETE units awarded the ETP employees assuming no forfeitures. For the years ended December 31, 2009 and 2008, the four months ended December 31, 2007, and the fiscal year ended August 31, 2007, ETP recognized non-cash compensation expense, net of forfeitures, of $6.4 million, $3.5 million, $3.6 million, and $5.2 million, respectively, as a result of these awards.

As of December 31, 2009, rights related to 530,000 ETE common units remain outstanding, for which we expect to recognize a total of $6.8 million in compensation expense over a weighted average period of 1.9 years

9.	INCOME TAXES:

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

	Years Ended December 31,						Four Months Ended December 31,		Year Ended August 31,
	2009			2008			2007		2007
Current provision:
Federal	$	(8,850	)	$	(180	)	$	2,990	$	7,896
State		9,657			12,241			5,831		10,432
Total		807			12,061			8,821		18,328
Deferred provision:
Federal		8,643			(8,531	)		516		(7,494	)
State		(221	)		278			612		557
Total		8,422			(8,253	)		1,128		(6,937	)
Total tax provision	$	9,229		$	3,808		$	9,949	$	11,391

On May 18, 2006, the State of Texas enacted House Bill 3, which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin, which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. For the years ended December 31, 2009 and 2008, the four months ended December 31, 2007, and the fiscal year ended August 31, 2007, we recognized current state income tax expense related to the Texas margin tax of $8.5 million, $10.5 million, $3.9 million and $6.9 million, respectively.

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. The difference between the statutory rate and the effective rate is summarized as follows:

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007
Federal statutory tax rate		35.00	%		35.00	%		35.00	%		35.00	%
State income tax rate net of federal benefit		1.08	%		1.59	%		2.57	%		1.25	%
Earnings not subject to tax at the Partnership level		(34.77	%)		(36.03	%)		(32.41	%)		(34.23	%)
Effective tax rate		1.31	%		0.56	%		5.16	%		2.02	%

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the deferred tax liability were as follows:

	December 31,			December 31,
	2009			2008
Property, plant and equipment	$	204,083		$	199,306
Other, net		(863	)		(3,846	)
Total deferred tax liability		203,220			195,460
Less current deferred tax asset (liability)		1,153			(589	)
Total long-term deferred tax liability	$	204,373		$	194,871

10.	MAJOR CUSTOMERS AND SUPPLIERS:

Our major customers are in the natural gas operations segments. Our natural gas operations have a concentration of customers in natural gas transmission, distribution and marketing, as well as industrial end-users while our NGL operations have a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively. Management believes that our portfolio of accounts receivable is sufficiently diversified to minimize any potential credit risk. No single customer accounted for 10% or more of our consolidated revenue.

We had gross segment purchases as a percentage of total purchases from major suppliers as follows:

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007
Propane segments
Unaffiliated:
M.P. Oils, Ltd.		15.1	%		14.9	%		14.2	%		20.7	%
Targa Liquids		14.3	%		15.0	%		15.9	%		22.6	%
Affiliated:
Enterprise		50.3	%		50.7	%		50.6	%		22.1	%

Enterprise GP Holdings, L.P. and its subsidiaries (“Enterprise” or “EPE”) became related parties on May 7, 2007, as discussed in Note 14. Titan purchases the majority of its propane from Enterprise pursuant to an agreement that expires in March 2010 and contains renewal and extension options.

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

This concentration of suppliers may impact our overall operations either positively or negatively. However, management believes that the diversification of suppliers is sufficient to enable us to purchase all of our supply needs at market prices without a material disruption of operations if supplies are interrupted from any of our existing sources. Although no assurances can be given that supplies of natural gas, propane and NGLs will be readily available in the future, we expect a sufficient supply to continue to be available.

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

Regulatory Matters

In August 2009, we filed an application for FERC authority to construct and operate the Tiger pipeline. Approval from the FERC is still pending.

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.

The Phoenix project, as filed with the FERC on September 15, 2006, includes the construction and operation of approximately 260 miles of 36-inch or larger diameter pipeline extending from Transwestern’s existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area and certain looping on Transwestern’s existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline. On November 15, 2007, the FERC issued an order granting Transwestern its Certificate of Public Convenience and Necessity (“Order”). Pursuant to the Order, Transwestern filed its initial Implementation Plan on November 14, 2007 and accepted the Order on November 19, 2007. The San Juan Lateral portion of the project was placed in service effective July 2008 and the pipeline to the Phoenix area was placed in service effective March 2009.

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 originally $1.4 billion. In September 2009, MEP issued senior notes totaling $800.0 million, the proceeds of which were used to repay borrowings under the MEP Facility. The senior notes issued by MEP are not guaranteed by ETP or KMP. In October 2009, the members made additional capital contributions to MEP, which MEP used to further reduce the outstanding borrowings under the MEP Facility. Subsequent to this repayment, the commitment amount under the MEP Facility was reduced from $1.4 billion to $275.0 million.

As of December 31, 2009, MEP had $29.5 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 $14.7 million and $16.6 million, respectively, as of December 31, 2009. The weighted average interest rate on the total amount outstanding as of December 31, 2009 was 3.3%.

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 ETP’s 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 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 December 31, 2009, FEP had $355.0 million of outstanding borrowings issued under the FEP Facility. ETP’s contingent obligation with respect to its 50% guarantee of FEP’s outstanding borrowings was $177.5 million as of December 31, 2009. The weighted average interest rate on the total amount outstanding as of December 31, 2009 was 3.2%.

Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. 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 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 $19.8 million, $17.2 million, $9.4 million and $33.2 million for the years ended December 31, 2009 and 2008, the four months ended December 31, 2007 and the fiscal year ended August 31, 2007, respectively.

Future minimum lease commitments for such leases are:

2010	$	27,216
2011		24,786
2012		22,522
2013		20,385
2014		17,907
Thereafter		214,088

We have forward commodity contracts, which are expected to be settled by physical delivery. Short-term contracts, which expire in less than one year require delivery of up to 390,564 MMBtu/d. Long-term contracts require delivery of up to 125,551 MMBtu/d and extend through May 2014.

During fiscal year 2007, we entered into a long-term agreement with CenterPoint Energy Resources Corp (“CenterPoint”) to provide the natural gas utility with firm transportation and storage services on our HPL System located along the Texas gulf coast region. Under the terms of the agreements, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas storage capacity in our Bammel storage facility.

We have a transportation agreement with TXU Portfolio Management Company, LP (“TXU Shipper”) to transport a minimum of 100,000 MMBtu per year through 2012. We also have two natural gas storage agreements with TXU Shipper to store gas at two natural gas facilities that are part of the ET Fuel System that expire in 2012. As of December 31, 2009 and 2008 and August 31, 2007, respectively, the Partnership was entitled to receive additional fees for the difference between actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month periods ended each May 31st. As a result, the Partnership recognized approximately $11.7 million, $10.7 million and $10.8 million in additional fees during the second quarter of 2008 and the third fiscal quarter of 2007, respectively.

We have signed long-term agreements with several parties committing firm transportation volumes into the East Texas pipeline. Those commitments include an agreement with XTO Energy Inc. (“XTO”) to deliver approximately 200,000 MMBtu/d of natural gas into the pipeline that expires in June 2012. Exxon Mobil Corporation (“ExxonMobil”) and XTO announced an agreement whereby ExxonMobil will acquire XTO. The pending acquisition, expected to be completed in the second quarter of 2010, is not expected to result in any changes to these commitments.

We also have two long-term agreements committing firm transportation volumes on certain of our transportation pipelines. The two contracts require an aggregated capacity of approximately 238,000 MMBtu/d of natural gas and extend through 2011.

Titan has a purchase contract with Enterprise (see Note 14) to purchase the majority of Titan’s propane requirements. The contract continues until March 2010 and contains renewal and extension options. The contract contains various service level agreements between the parties.

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

We have commitments to make capital contributions to our joint ventures, for which we expect to make capital contributions of between $90 million and $105 million during 2010.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and propane are flammable, combustible gases. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverages 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 Natural Gas Act (“NGA”). The FERC alleges 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 our 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. 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 exceeding 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.

We made the $5.0 million payment and established the $25.0 million fund in October 2009. The allocation of the $25.0 million fund is expected to be determined 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 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.

ETP has 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. ETP 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 28, 2009, these decisions were appealed by the plaintiffs to the United States Court of Appeals for the 5th Circuit.

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 ETP’s 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 10, 2009, this decision was appealed by the plaintiff to the United States Court of Appeals for the 5th Circuit.

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. ETP records accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, we made the $5.0 million payment and established the $25.0 million fund in October 2009. While 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, ETP may not be able to realize such tax benefits. Although this 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 their accrual related to these matters as developments related to these matters occur and ETP will adjust their accrual if ETP determines that it is probable that the amount ETP may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of ETP’s 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 ETP’s 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 its liquidity.

In re Natural Gas Royalties Qui Tam Litigation. MDL Docket No. 1293 (D. WY), Jack Grynberg, an individual, has filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against Transwestern. Transwestern believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which were filed with and approved by the FERC. As a result, Transwestern believes that is has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Transwestern complied with the terms of its tariffs) and will continue to vigorously defend against them, including any appeal which may be taken from the dismissal of the Grynberg case. A hearing was held on April 24, 2007 regarding Transwestern’s Supplemental Brief for Attorneys’ fees, which was filed on January 8, 2007, and the issues are submitted and are awaiting a decision. Grynberg moved to have the cases he appealed remanded to the district court for consideration in light of a recently-issued Supreme Court case. The defendants/appellees opposed the motion. The Tenth Circuit motions panel referred the remand motion to the merits panel to be carried with the appeals. Grynberg’s opening brief was filed on or about July 31, 2007. Appellee’s opposition brief was filed on or about November 21, 2007. Appellee Transwestern filed its separate response brief on January 11, 2008 and Grynberg’s reply brief was filed in June 2008 and the hearing on all briefs was held in September 2008. On March 17, 2009, the Tenth Circuit affirmed the District Court’s dismissal. Appellant sought appellate rehearing on the matter and the petition for rehearing was denied on May 4, 2009. A petition for writ of certiorari was filed by the Appellant on August 3, 2009, and the Supreme Court denied the petition for writ of certiorari on October 5, 2009. We do not believe the outcome of this case will have a material adverse effect on our financial position, results of operations or cash flows.

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 December 31, 2009 and 2008, accruals of approximately $11.1 million and $8.5 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.

As of December 31, 2008, an accrual of $21.0 million was recorded as accrued and other current liabilities and other non-current liabilities on our consolidated balance sheets for our contingencies and current litigation matters, excluding accruals related to environmental matters, and we did not have any such accruals as of December 31, 2009.

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 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 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 $8.6 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 EPA’s 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 U.S. Environmental Protection Agency (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 December 31, 2009 or our December 31, 2008 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 December 31, 2009 and 2008, accruals on an undiscounted basis of $12.6 million and $13.3 million, respectively, 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.

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 years ended December 31, 2009 and 2008, $31.4 million and $23.3 million, respectively, of capital costs and $18.5 million and $13.1 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.

12.	PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

See Note 2 for further discussion of our accounting for derivative instruments and hedging activities.

Commodity Price Risk

The following table details the outstanding commodity-related derivatives:

		December 31, 2009					December 31, 2008
	Commodity	Notional Volume MMBtu			Maturity		Notional Volume MMBtu			Maturity
Mark to Market Derivatives
Basis Swaps IFERC/NYMEX	Gas		72,325,000			2010-2011		15,720,000			2009-2011
Swing Swaps IFERC	Gas		(38,935,000	)		2010		(58,045,000	)		2009
Fixed Swaps/Futures	Gas		4,852,500			2010-2011		(20,880,000	)		2009-2010
Options - Puts	Gas		2,640,000			2010		-			N/A
Options - Calls	Gas		(2,640,000	)		2010		-			N/A
Forwards/Swaps - in Gallons	Propane		6,090,000			2010		47,313,002			2009

Fair Value Hedging Derivatives
Basis Swaps IFERC/NYMEX	Gas		(22,625,000	)		2010		-			N/A
Fixed Swaps/Futures	Gas		(27,300,000	)		2010		-			N/A
Hedged Item - Inventory	Gas		27,300,000			2010		-			N/A

Cash Flow Hedging Derivatives
Basis Swaps IFERC/NYMEX	Gas		(13,225,000	)		2010		(9,085,000	)		2009
Fixed Swaps/Futures	Gas		(22,800,000	)		2010		(9,085,000	)		2009
Forwards/Swaps - in Gallons	Propane/Ethane		20,538,000			2010		-			N/A

We expect gains of $2.0 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.

As of July 2008, we no longer engage in the trading of commodity derivative instruments that are not substantially offset by physical or other commodity derivative positions. As a result, we no longer have any material exposure to market risk from such activities. The derivative contracts that were previously entered into for trading purposes were recognized in the consolidated balance sheets at fair value, and changes in the fair value of these derivative instruments are recognized in revenue in the consolidated statements of operations on a net basis. Trading activities, including trading of physical gas and financial derivative instruments, resulted in net losses of approximately $26.2 million for the year ended December 31, 2008, net losses of approximately $2.3 million for the four-month transition period ended December 31, 2007 and net gains of approximately $2.2 million for the fiscal year ended August 31, 2007. There were no gains or losses associated with trading activities during the year ended December 31, 2009.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. We manage a portion of our current and future interest rate exposures by utilizing interest rate swaps. We have the following interest rate swaps outstanding as of December 31, 2009:

Interest rate swaps with a notional amount of $300.0 million to pay an average fixed rate of 5.20% and receive a floating rate based on LIBOR. These swaps settle in May 2016;

Interest rate swaps with a notional amount of $500.0 million to pay a fixed rate of 4.57% and receive a floating rate based on LIBOR. These swaps settle in November 2012 with a cancellable option in November 2010; and,

Interest rate swaps with a notional amount of $700.0 million to pay an average fixed rate of 4.84% and receive a floating rate based on LIBOR. These swaps settle in November 2012.

In January 2010, we entered into interest rate swaps with notional amounts of $350.0 million and $750.0 million to pay a floating rate based on LIBOR and receive a fixed rate that mature in July 2013 and February 2015, respectively. These swaps hedge against changes in the fair value of our fixed rate debt.

Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of December 31, 2009 and December 31, 2008:

		Fair Value of Derivative Instruments
		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	December 31, 2009		December 31, 2008		December 31, 2009			December 31, 2008

Derivatives designated as hedging instruments:
Commodity Derivatives (margin deposits)	Deposits Paid to Vendors	$	669	$	10,665	$	(24,035	)	$	(1,504	)
Commodity Derivatives	Price Risk Management Assets/Liabilities		8,443		918		(201	)		(119	)
Interest Rate Swap Derivatives	Price Risk Management Assets/Liabilities		-		-		(61,879	)		(71,042	)

Total derivatives designated as hedging instruments		$	9,112	$	11,583	$	(86,115	)	$	(72,665	)

Derivatives not designated as hedging instruments:
Commodity Derivatives (margin deposits)	Deposits Paid to Vendors	$	72,851	$	432,614	$	(36,950	)	$	(335,685	)
Commodity Derivatives	Price Risk Management Assets/Liabilities		3,928		17,244		(241	)		(55,954	)
Interest Rate Swap Derivatives	Price Risk Management Assets/Liabilities		-		-		(76,157	)		(149,765	)

Total derivatives not designated as hedging instruments		$	76,779	$	449,858	$	(113,348	)	$	(541,404	)

Total derivatives		$	85,891	$	461,441	$	(199,463	)	$	(614,069	)

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

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 consolidated balance sheets. The Partnership had net deposits with counterparties of $79.7 million and $78.2 million as of December 31, 2009 and December 31, 2008, respectively.

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

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective and Ineffective Portion)	Change in Value Recognized in OCI on Derivatives (Effective Portion)
		Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
		2009			2008			2007			2007
Derivatives in cash flow hedging relationships:

Commodity Derivatives	Cost of Products Sold	$	3,143		$	17,461		$	21,406		$	181,765
Interest Rate Swap Derivatives	Interest Expense		(14,705	)		(57,676	)		(23,846	)		(578	)

Total		$	(11,562	)	$	(40,215	)	$	(2,440	)	$	181,187

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective and Ineffective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Years Ended December 31,						Four Months Ended December 31,		Year Ended August 31,
		2009			2008			2007		2007
Derivatives in cash flow hedging relationships:

Commodity Derivatives	Cost of Products Sold	$	9,924		$	42,874		$	8,673	$	162,340
Interest Rate Swap Derivatives	Interest Expense		(26,882	)		(11,339	)		650		3,879

Total		$	(16,958	)	$	31,535		$	9,323	$	166,219

	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective and Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion of Derivatives
		Years Ended December 31,					Four Months Ended December 31,			Year Ended August 31,
		2009		2008			2007			2007
Derivatives in cash flow hedging relationships:

Commodity Derivatives	Cost of Products Sold	$	-	$	(8,347	)	$	8,472		$	183
Interest Rate Swap Derivatives	Interest Expense		-		-			(2	)		(1,813	)

Total		$	-	$	(8,347	)	$	8,470		$	(1,630	)

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives representing hedge ineffectiveness and amount excluded from the assessment of effectiveness
		Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
Derivatives in fair value hedging relationships:		2009		2008		2007		2007

Commodity Derivatives
(including hedged items)	Cost of Products Sold	$	60,045	$	-	$	-	$	-

Total		$	60,045	$	-	$	-	$	-

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Years Ended December 31,					Four Months Ended December 31,			Year Ended August 31,
Derivatives not designated as hedging instruments:		2009		2008			2007			2007

Commodity Derivatives	Cost of Products Sold	$	99,807	$	12,478		$	9,886		$	30,028
Trading Commodity Derivatives	Revenue		-		(28,283	)		(2,298	)		5,228
Interest Rate Swap Derivatives	Gains (Losses) on Non-hedged Interest Rate Derivatives		33,619		(128,423	)		(28,683	)		29,081

Total		$	133,426	$	(144,228	)	$	(21,095	)	$	64,337

We recognized an $18.6 million unrealized loss, a $35.5 million unrealized gain, a $13.2 million unrealized gain and an $8.5 million unrealized loss on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships and amounts classified as trading activity) for the years ended December 31, 2009 and 2008, four months ended December 31, 2007 and the year August 31, 2007, respectively. In addition, for the year ended December 31, 2009, we recognized unrealized gains of $48.6 million on commodity derivatives and related hedged inventory accounted for as fair value hedges. There were no unrealized gains or losses on fair value hedging commodity derivatives in the prior years since we commenced fair hedge accounting on our storage inventory in April 2009.

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.

13.	RETIREMENT BENEFITS:

ETP sponsors a 401(k) savings plan, which covers virtually all employees. Employer matching contributions are calculated using a formula based on employee contributions. Prior to 2009, employer-matching contributions were discretionary. We made matching contributions of $9.8 million, $9.7 million, $2.6 million and $8.5 million to the 401(k) savings plan for the years ended December 31, 2009 and 2008, the four months ended December 31, 2007, and the fiscal year ended August 31, 2007, respectively.

14.	RELATED PARTY TRANSACTIONS:

On May 7, 2007, Ray Davis, previously the Co-Chairman of ETE and Co-Chairman and Co-Chief Executive Officer of ETP (retired August 15, 2007), and Natural Gas Partners VI, L.P. (“NGP”) and affiliates of each, sold approximately 38,976,090 ETE Common Units (17.6% of the outstanding Common Units of ETE) to Enterprise. In addition to the purchase of ETE Common Units, Enterprise acquired a non-controlling equity interest in our General Partner, LE GP, LLC (“LE GP”). Cash consideration paid by Enterprise totaled approximately $1.65 billion, reflecting a purchase price of $42.00 per ETE Common Unit. As a result of these transactions, EPE and its subsidiaries are considered related parties for financial reporting purposes.

On December 23, 2009, Dan L. Duncan and Ralph S. Cunningham were appointed as directors of our general partner. Mr. Duncan is Chairman and a director of EPE Holdings, LLC, the general partner of Enterprise; Chairman and a director of Enterprise Products GP, LLC, the general partner of Enterprise Products Partners L.P., or EPD; and Group Co-Chairman of EPCO, Inc. TEPPCO Partners, L.P., or TEPPCO, is also an affiliate of EPE. Dr. Cunningham is the President and Chief Executive Officer of EPE Holdings, LLC, the general partner of Enterprise. These entities and other affiliates of Enterprise are referred to herein collectively as the “Enterprise Entities.” Mr. Duncan directly or indirectly beneficially owns various interests in the Enterprise Entities, including various general partner interests and approximately 77.1% of the common units of Enterprise, and approximately 34% of the common units of EPD. On October 26, 2009, TEPPCO became a wholly owned subsidiary of Enterprise.

Our propane operations routinely enter into purchases and sales of propane with certain of the Enterprise Entities, including purchases under a long-term contract of Titan to purchase the majority of its propane requirements through certain of the Enterprise Entities. This agreement was in effect prior to our acquisition of Titan in 2006 and expires in March 2010 and contains renewal and extension options.

From time to time, our natural gas operations purchase from, and sell to, the Enterprise Entities natural gas and NGLs, in the ordinary course of business. We have a monthly natural gas storage contract with TEPPCO. Our natural gas operations and the Enterprise Entities transport natural gas on each other’s pipelines and share operating expenses on jointly-owned pipelines.

The following table presents sales to and purchases from affiliates of Enterprise. Amounts reflected below for the year ended August 31, 2007 include transactions beginning on May 7, 2007, the date Enterprise became an affiliate. Volumes are presented in thousands of gallons for propane and NGLs and in billions of Btus for natural gas.

		Years Ended December 31,										Four Months Ended December 31,					Year Ended August 31,
		2009					2008					2007					2007

	Product	Volumes		Dollars			Volumes		Dollars			Volumes		Dollars			Volumes		Dollars
Propane Operations:
Sales	Propane		20,370	$	14,046			13,230	$	19,769			2,982	$	4,619			1,470	$	1,725
	Derivatives		-		5,915			-		2,442			-		1,857			-		22

Purchases	Propane		307,525	$	305,148			318,982	$	472,816			125,141	$	192,580			61,660	$	74,688
	Derivatives		-		38,392			-		20,993			-		-			-		1

Natural Gas Operations:
Sales	NGLs		477,908	$	374,020			58,361	$	96,974			3,240	$	4,726			464	$	648
	Natural Gas		11,532		44,212			6,256		52,205			2,036		11,452			1,495		9,768
	Fees		-		(3,899	)		-		5,093			-		610			-		-

Purchases	Natural Gas
	Imbalances		176	$	1,164			3,488	$	(6,485	)		313	$	(911	)		3,120	$	22,677
	Natural Gas		10,561		49,559			13,457		120,837			3,577		23,341			1,541		7,501
	Fees		-		(2,195	)		-		876			-		311			-		-

As of December 31, 2009 and 2008, Titan had forward mark-to-market derivatives for approximately 6.1 million and 45.2 million gallons of propane at a fair value asset of $3.3 million and a fair value liability of $40.1 million, respectively, with Enterprise. In addition, as of December 31, 2009, Titan had forward derivatives accounted for as cash flow hedges of 20.5 million gallons of propane at a fair value asset of $8.4 million with Enterprise.

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

	December 31, 2009		December 31, 2008
Natural Gas Operations:
Accounts receivable	$	47,005	$	11,558
Accounts payable		3,518		567
Imbalance payable		694		(547	)

Propane Operations:
Accounts receivable	$	3,386	$	111
Accounts payable		31,642		33,308

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

	December 31, 2009		December 31, 2008
MEP	$	632	$	2,805
Energy Transfer Technologies, Ltd.		-		16
McReynolds Energy		-		202
Others		871		450
Total accounts receivable from related companies excluding Enterprise	$	1,503	$	3,473

Effective August 17, 2009, we acquired 100% of the membership interests of Energy Transfer Group, L.L.C. (“ETG”), which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including ETP. The membership interests of ETG were contributed to us by Mr. Warren and by two entities, one of which is controlled by a director of the General Partner of ETP’s general partner and the other of which is controlled by a member of ETP’s management. In exchange, the former members acquired the right to receive (in cash or Common Units) future amounts to be determined based on the terms of the contribution arrangement. These contingent amounts are to be determined in 2014 and 2017, and the former members of ETG may receive payments contingent on the acquired operations performing at a level above the average return required by ETP for approval of its own growth projects during the period since acquisition. In addition, the former members may be required to make cash payments to us under certain circumstances. In connection with this transaction, we assumed liabilities of $33.5 million and recorded goodwill of $1.7 million.

Prior to our acquisition of ETG in August 2009, our natural gas midstream and intrastate transportation and storage operations secured compression services from ETT. The terms of each arrangement to provide compression services were, in the opinion of independent directors of the General Partner, no more or less favorable than those available from other providers of compression services. During the years ended December 31, 2009 (through the ETG acquisition date) and 2008, the four months ended December 31, 2007 and the fiscal year ended August 31, 2007, we made payments totaling $3.4 million, $9.4 million, $0.8 million, and $2.4 million, respectively, to ETG for compression services provided to and utilized in our natural gas midstream and intrastate transportation and storage operations.

The Partnership pays ETP an annual administrative fee of $0.5 million for the provision of various general and administrative services for ETE’s benefit.

The Chief Executive Officer (“CEO”) of ETP’s General Partner, Mr. Kelcy Warren, voluntarily determined that after 2007, his salary would be reduced to $1.00 plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits. Mr. Warren also declined future cash bonuses and future equity awards under our 2004 Unit Plan. We recorded non-cash compensation expense and an offsetting capital contribution of $1.3 million ($0.5 million in salary and $0.8 million in accrued bonuses) for each of the years ended December 31, 2009 and 2008 as an estimate of the reasonable compensation level for the CEO position.

15.	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:

intrastate transportation and storage

interstate transportation

midstream

retail propane and other retail propane related operations

Segments below the quantitative thresholds are classified as “other”. The components of the “other” classification have not met any of the quantitative thresholds for determining reportable segments. Management has included the wholesale propane and natural gas compression services operations in “other” for all periods presented in this report because such operations are not material.

Midstream and intrastate transportation and storage segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The volumes and results of operations data for fiscal year 2007 do not include the interstate operations for periods prior to Transwestern’s acquisition on December 1, 2006.

See “Business Operations” in Note 1 for a description of the operations of each of our reportable segments.

We evaluate the performance of our operating segments based on operating income exclusive of general partnership selling, general and administrative expenses, gains (losses) on disposal of assets, interest expense, equity in earnings (losses) from affiliates and income tax expense (benefit). Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income. We began allocating administration expenses from the Partnership to our Operating Companies using the Modified Massachusetts Formula Calculation (“MMFC”) which is based on factors such as respective segments’ gross margins, employee costs, and property and equipment.

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. The amounts allocated for the periods presented are as follows:

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007
Costs allocated from ETP to operating subsidiaries:
Midstream and intrastate transportation and storage operations	$	15,776	$	19,834	$	6,761	$	11,357
Interstate operations		4,922		5,750		2,613		4,388
Retail propane and other retail propane related operations		12,113		12,664		5,992		10,067
Total	$	32,811	$	38,248	$	15,366	$	25,812

Costs allocated from operating subsidiaries to ETP:
Midstream and intrastate transportation and storage operations	$	6,699	$	10,649	$	2,440	$	5,221
Retail propane and other retail propane related operations		412		2,428		850		2,187
Total	$	7,111	$	13,077	$	3,290	$	7,408

The following tables present the financial information by segment for the following periods:

							Four Months
							Ended			Year Ended
	Years Ended December 31,						December 31,			August 31,
	2009			2008			2007			2007
Revenues:
Intrastate transportation and storage
Revenues from external customers	$	1,773,528		$	3,379,424		$	929,357		$	3,085,940
Intersegment revenues		618,016			2,255,180			325,044			829,992
		2,391,544			5,634,604			1,254,401			3,915,932

Interstate transportation		270,213			244,224			76,000			178,663

Midstream
Revenues from external customers		2,060,451			4,029,508			826,835			2,121,289
Intersegment revenues		380,709			1,312,885			339,478			732,207
		2,441,160			5,342,393			1,166,313			2,853,496

Retail propane and other retail propane related - revenues from external customers		1,292,583			1,624,010			511,258			1,284,867

All other:
Revenues from external customers		20,520			16,201			5,892			121,278
Intersegment revenues		1,145			-			-			-
		21,665			16,201			5,892			121,278

Eliminations		(999,870	)		(3,568,065	)		(664,522	)		(1,562,199	)
Total revenues	$	5,417,295		$	9,293,367		$	2,349,342		$	6,792,037

Cost of products sold:
Intrastate transportation and storage	$	1,393,295		$	4,467,552		$	964,568		$	3,137,712
Midstream		2,116,279			4,986,495			1,043,191			2,632,187
Retail propane and other retail propane related		596,002			1,038,722			325,158			759,634
All other		16,350			13,376			5,259			110,872
Eliminations		(999,870	)		(3,568,065	)		(664,522	)		(1,562,199	)
Total cost of products sold	$	3,122,056		$	6,938,080		$	1,673,654		$	5,078,206

Depreciation and amortization:
Intrastate transportation and storage	$	115,884		$	92,979		$	23,429		$	64,423
Interstate transportation		48,297			37,790			12,305			27,972
Midstream		74,787			63,287			14,943			27,331
Retail propane and other retail propane related		83,476			79,717			24,537			70,833
All other		2,580			599			192			824
Total depreciation and amortization	$	325,024		$	274,372		$	75,406		$	191,383

Operating income (loss):
Intrastate transportation and storage	$	618,500		$	710,070		$	169,361		$	479,820
Interstate transportation		138,233			124,676			29,657			95,650
Midstream		136,790			162,471			71,853			119,233
Retail propane and other retail propane related		229,229			114,564			46,747			124,263
All other		(8,658	)		(2,032	)		(796	)		1,735
Selling general and administrative expenses not allocated to segments		(3,696	)		(10,846	)		(171	)		(11,365	)
Total operating income	$	1,110,398		$	1,098,903		$	316,651		$	809,336

Other items not allocated by segment:
Interest expense, net of interest capitalized	$	(468,420	)	$	(357,541	)	$	(103,375	)	$	(279,986	)
Equity in earnings (losses) of affiliates		20,597			(165	)		(94	)		5,161
Gains (losses) on disposal of assets		(1,564	)		(1,303	)		14,310			(6,310	)
Gains (losses) on non-hedged interest rate derivatives		33,619			(128,423	)		(28,683	)		29,081
Allowance for equity funds used during construction		10,557			63,976			7,276			4,948
Other, net		1,913			8,115			(13,327	)		1,129
Income tax expense		(9,229	)		(3,808	)		(9,949	)		(11,391	)
		(412,527	)		(419,149	)		(133,842	)		(257,368	)
Net income	$	697,871		$	679,754		$	182,809		$	551,968

	As of December 31,						As of August 31,
	2009		2008		2007		2007
Total assets:
Intrastate transportation and storage	$	5,162,164	$	4,911,770	$	4,254,514	$	3,814,391
Interstate transportation		3,313,837		2,487,078		1,834,941		1,653,363
Midstream		1,653,921		1,674,028		1,444,446		943,760
Retail propane and other retail propane related		1,784,353		1,810,953		1,778,426		1,593,863
All other		246,234		186,073		149,767		177,712
Total	$	12,160,509	$	11,069,902	$	9,462,094	$	8,183,089

	Years Ended December 31,				Four Months Ended December 31,		Year Ended August 31,
	2009		2008		2007		2007
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Intrastate transportation and storage	$	378,494	$	993,886	$	320,965	$	827,859
Interstate transportation		99,341		720,186		167,343		1,345,637
Midstream		95,081		267,900		414,722		201,646
Retail propane and other retail propane related		62,953		130,358		47,553		65,125
All other		44,911		3,072		953		2,015
Total	$	680,780	$	2,115,402	$	951,536	$	2,442,282

16.	QUARTERLY FINANCIAL DATA (UNAUDITED):

Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year. HOLP’s and Titan’s businesses are seasonal due to weather conditions in their service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to commercial and industrial customers are less weather sensitive. ETC OLP’s business is also seasonal due to the operations of ET Fuel System and the HPL System. We expect margin related to the HPL System operations to be higher during the periods from November through March of each year and lower during the periods from April through October of each year due to the increased demand for natural gas during the cold weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

	Quarter Ended
2009:	March 31		June 30		September 30		December 31		Total Year

Revenues	$	1,629,974	$	1,151,690	$	1,129,849	$	1,505,782	$	5,417,295
Gross Profit		670,835		525,697		451,701		647,006		2,295,239
Operating income		356,098		215,031		173,501		365,768		1,110,398
Net income		279,750		141,758		34,267		242,096		697,871
Limited Partners’ interest in net income		151,067		104,053		46,824		139,159		441,103
Basic net income per limited partner unit	$	0.68	$	0.47	$	0.21	$	0.62	$	1.98
Diluted net income per limited partner unit	$	0.68	$	0.47	$	0.21	$	0.62	$	1.98

	Quarter Ended
2008:	March 31		June 30		September 30		December 31		Total Year

Revenues	$	2,639,245	$	2,653,351	$	2,206,090	$	1,794,681	$	9,293,367
Gross Profit		659,527		529,279		572,636		593,845		2,355,287
Operating income		367,929		221,940		256,264		252,770		1,098,903
Net income		267,158		166,818		185,116		60,662		679,754
Limited Partners’ interest in net income		126,313		120,021		105,053		22,496		373,883
Basic net income per limited partner unit	$	0.57	$	0.54	$	0.47	$	0.10	$	1.68
Diluted net income per limited partner unit	$	0.57	$	0.54	$	0.47	$	0.10	$	1.68

17.	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

	December 31,			December 31,
	2009			2008

ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	62		$	62
Accounts receivable from related companies		97			459
Other current assets		1,287			163
Total current assets		1,446			684

ADVANCES TO AND INVESTMENT IN AFFILIATES		1,711,928			1,662,074
INTANGIBLES AND OTHER ASSETS, net		5,574			8,581
Total assets	$	1,718,948		$	1,671,339


LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	178		$	798
Accounts payable to affiliates		5,024			3,034
Accrued interest		1,480			9,222
Accrued and other current liabilities		127			912
Price risk management liabilities		64,704			47,453
Total current liabilities		71,513			61,419

LONG-TERM DEBT, less current maturities		1,573,951			1,571,642
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		73,332			121,710

COMMITMENTS AND CONTINGENCIES
		1,718,796			1,754,771

PARTNERS’ CAPITAL (DEFICIT):
General Partner		368			155
Limited Partner - Common Unitholders (222,898,248 and 222,829,956 units authorized, issued and outstanding at December 31, 2009 and 2008, respectively		53,412			(15,762	)

Accumulated other comprehensive loss		(53,628	)		(67,825	)
Total partners’ capital (deficit)		152			(83,432	)

Total liabilities and partners’ capital (deficit)	$	1,718,948		$	1,671,339

STATEMENTS OF OPERATIONS

	Years Ended December 31,						Four Months Ended December 31,			Year Ended August 31,
	2009			2008			2007			2007


SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(4,970	)	$	(6,453	)	$	(2,875	)	$	(8,496	)

OTHER INCOME (EXPENSE):
Interest expense		(74,049	)		(91,822	)		(37,071	)		(104,405	)
Equity in earnings of affiliates		526,383			551,835			168,547			435,247
Losses on non-hedged interest rate derivatives		(5,620	)		(77,435	)		(27,670	)		(1,952	)
Other, net		79			(1,056	)		(8,128	)		(405	)

INCOME BEFORE INCOME TAXES		441,823			375,069			92,803			319,989

Income tax expense (benefit)		(650	)		25			126			629

NET INCOME		442,473			375,044			92,677			319,360

GENERAL PARTNER'S INTEREST IN NET INCOME		1,370			1,161			287			1,048

LIMITED PARTNERS' INTEREST IN NET INCOME	$	441,103		$	373,883		$	92,390		$	318,312

STATEMENTS OF CASH FLOWS

							Four Months			Year
							Ended			Ended
	Years Ended December 31,						December 31,			August 31,
	2009			2008			2007			2007

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	468,969		$	436,819		$	77,360		$	239,777

CASH FLOWS FROM INVESTING ACTIVITIES:
Advances to and investment in subsidiaries		-			-			-			(1,200,000	)
Net cash used in investing activities		-			-			-			(1,200,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		67,505			190,533			1,255			1,252,662
Principal payments on debt		(65,816	)		(191,464	)		-			(367,529	)
Equity offerings		-			-			-			372,434
Cash distributions to Partners		(470,658	)		(435,868	)		(87,174	)		(276,997	)
Debt issuance costs		-			-			-			(11,881	)
Net cash provided by (used in) financing activities		(468,969	)		(436,799	)		(85,919	)		968,689

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		-			20			(8,559	)		8,466

CASH AND CASH EQUIVALENTS, beginning of period		62			42			8,601			135

CASH AND CASH EQUIVALENTS, end of period	$	62		$	62		$	42		$	8,601

18.	COMPARATIVE INFORMATION FOR THE FOUR MONTHS ENDED DECEMBER 31, 2007:

The unaudited financial information for the four month period ended December 31, 2006, contained herein is presented for comparative purposes only and does not contain related financial statement disclosures that would be required with a complete set of financial statements presented in conformity with accounting principles generally accepted in the United States of America. Certain financial statement amounts have been adjusted due to the adoption of new accounting standards in 2009. See Note 2.

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

	Four Months Ended December 31,
	2007			2006
REVENUES:
Natural gas operations	$	1,832,192		$	1,668,667
Retail propane		471,494			409,821
Other		45,656			83,978
Total revenues		2,349,342			2,162,466

COSTS AND EXPENSES:
Cost of products sold - natural gas operations		1,343,237			1,382,473
Cost of products sold - retail propane		315,698			256,994
Cost of products sold - other		14,719			50,376
Operating expenses		221,757			173,365
Depreciation and amortization		75,406			52,840
Selling, general and administrative		61,874			43,602
Total costs and expenses		2,032,691			1,959,650

OPERATING INCOME		316,651			202,816

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(103,375	)		(82,979	)
Equity in earnings (losses) of affiliates		(94	)		4,743
Gain on disposal of assets		14,310			2,212
Other income (expense), net		(34,734	)		2,248

INCOME BEFORE INCOME TAX EXPENSE		192,758			129,040
Income tax expense		9,949			2,155

NET INCOME		182,809			126,885

LESS: NET INCOME ATTRIBUTABLE TO
NONCONTROLLING INTERESTS		90,132			50,204

NET INCOME ATTRIBUTABLE TO PARTNERS		92,677			76,681

GENERAL PARTNER'S INTEREST IN NET INCOME		287			290

LIMITED PARTNERS' INTEREST IN NET INCOME	$	92,390		$	76,391

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.41		$	0.45

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,829,916			170,691,287

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.41		$	0.45

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,829,916			170,691,287

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

	Four Months Ended December 31,
	2007			2006

Net income	$	182,809		$	126,885

Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		(17,970	)		(23,698	)
Change in value of derivative instruments accounted for as cash flow hedges		(2,221	)		158,916
Change in value of available-for-sale securities		(98	)		(401	)
		(20,289	)		134,817

Comprehensive income		162,520			261,702

Less: Comprehensive income attributable to non-controlling interest		92,832			117,677

Comprehensive income attributable to partners	$	69,688		$	144,025

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

	Four Months Ended December 31,
	2007			2006
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:
Net income	$	182,809		$	126,885
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		75,406			52,840
Amortization in interest expense		2,441			1,697
Provision for loss on accounts receivable		544			563
Gain on disposal of assets		(14,310	)		(2,212	)
Non-cash unit-based compensation expense		8,137			4,385
Non-cash executive compensation		442			-
Distributions in excess of (less than) equity in earnings of affiliates, net		4,448			(4,742	)
Deferred income taxes		37			(3,199	)
Other non-cash		(2,069	)		-
Net change in operating assets and liabilities, net of acquisitions		(49,250	)		218,586
Net cash provided by operating activities		208,635			394,803

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(337,092	)		(67,089	)
Capital expenditures		(651,228	)		(336,473	)
Contributions in aid of construction costs		3,493			4,984
Advances to and investment in affiliates		(32,594	)		(953,247	)
Proceeds from the sale of assets		21,478			7,644
Net cash used in investing activities		(995,943	)		(1,344,181	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,742,802			2,911,149
Principal payments on debt		(1,062,272	)		(1,941,610	)
Subsidiary equity offering net of issue costs		234,887			-
Net proceeds from issuance of Common Units		-			213,287
Distributions to Partners		(87,174	)		(39,867	)
Debt issuance costs		(211	)		(21,302	)
Distributions to noncontrolling interests		(61,517	)		(75,868	)
Net cash provided by financing activities		766,515			1,045,789

INCREASE IN CASH AND CASH EQUIVALENTS		(20,793	)		96,411
CASH AND CASH EQUIVALENTS, beginning of period		77,350			26,204
CASH AND CASH EQUIVALENTS, end of period	$	56,557		$	122,615

NON-CASH INVESTING AND FINANCING ACTIVITIES
SUPPLEMENTAL CASH FLOW INFORMATION:

NON-CASH INVESTING ACTIVITIES:
Capital expenditures accrued	$	87,622		$	13,294
Gain from subsidiary issuance of common units (recorded in partners' capital)	$	48,932		$	-

NON-CASH FINANCING ACTIVITIES:
Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	3,896		$	532,631
Issuance of common units in connection with certain acquisitions	$	1,400		$	-

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest, net of interest capitalized	$	79,084		$	50,480
Cash paid during the period for income taxes	$	9,135		$	6,197