Exhibit 99.1

Report of Independent Registered Public Accounting Firm

Partners

Energy Transfer Partners, L.P.

We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income, partners’ capital, 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 Partners, 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 calculation of earnings per unit.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Energy Transfer Partners, 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 PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31, 2009		December 31, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	68,183	$	91,902
Marketable securities		6,055		5,915
Accounts receivable, net of allowance for doubtful accounts		566,522		591,257
Accounts receivable from related companies		57,369		17,895
Inventories		389,954		272,348
Exchanges receivable		23,136		45,209
Price risk management assets		12,371		5,423
Other current assets		148,373		153,452
Total current assets		1,271,963		1,183,401
PROPERTY, PLANT AND EQUIPMENT, net		8,670,247		8,296,085
ADVANCES TO AND INVESTMENTS IN AFFILIATES		663,298		10,110
GOODWILL		745,505		743,694
INTANGIBLES AND OTHER ASSETS, net		383,959		394,199
Total assets	$	11,734,972	$	10,627,489

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

2

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31, 2009		December 31, 2008
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	358,997	$	381,135
Accounts payable to related companies		38,842		34,547
Exchanges payable		19,203		54,636
Price risk management liabilities		442		94,978
Interest payable		136,222		106,259
Accrued and other current liabilities		228,946		433,794
Current maturities of long-term debt		40,887		45,198
Total current liabilities		823,539		1,150,547
LONG-TERM DEBT, less current maturities		6,176,918		5,618,549
DEFERRED INCOME TAXES		112,997		100,597
OTHER NON-CURRENT LIABILITIES		21,810		14,727
COMMITMENTS AND CONTINGENCIES (Note 10)
		7,135,264		6,884,420
PARTNERS’ CAPITAL:
General Partner		174,884		161,159
Limited Partners:
Common Unitholders (179,274,747 and 152,102,471 units authorized, issued and outstanding at December 31, 2009 and 2008, respectively)		4,418,017		3,578,997
Class E Unitholders (8,853,832 units authorized, issued and outstanding - held by subsidiary and reported as treasury units)		-		-
Accumulated other comprehensive income		6,807		2,913
Total partners’ capital		4,599,708		3,743,069
Total liabilities and partners’ capital	$	11,734,972	$	10,627,489

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

	Years Ended December 31,						Four Months Ended December 31, 2007			Year Ended August 31, 2007
	2009			2008
				As Adjusted (Note 2)			As Adjusted (Note 2)			As Adjusted (Note 2)
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			126,113			45,824			227,072
Total revenues		5,417,295			9,293,868			2,349,510			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		312,803			262,151			71,333			179,162
Selling, general and administrative		173,936			194,227			59,132			145,417
Total costs and expenses		4,289,688			8,176,289			2,025,876			5,962,385
OPERATING INCOME		1,127,607			1,117,579			323,634			829,652
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(394,274	)		(265,701	)		(66,298	)		(175,563	)
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		39,239			(50,989	)		(1,013	)		31,032
Allowance for equity funds used during construction		10,557			63,976			7,276			4,948
Other, net		2,157			9,306			(5,202	)		2,019
INCOME BEFORE INCOME TAX EXPENSE		804,319			872,703			272,613			690,939
Income tax expense		12,777			6,680			10,789			13,658
NET INCOME		791,542			866,023			261,824			677,281
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		-			-			-			1,142
NET INCOME ATTRIBUTABLE TO PARTNERS		791,542			866,023			261,824			676,139
GENERAL PARTNER’S INTEREST IN NET INCOME		365,362			315,896			91,011			235,876
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	426,180		$	550,127		$	170,813		$	440,263
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	2.53		$	3.74		$	1.24		$	3.32
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		167,337,192			146,871,261			137,624,934			132,618,053
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	2.53		$	3.74		$	1.24		$	3.31
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		167,768,981			147,090,608			138,013,366			132,877,152

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

	Years Ended December 31,						Four Months Ended December 31, 2007			Year Ended August  31, 2007
	2009			2008
Net income	$	791,542		$	866,023		$	261,824		$	677,281
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		(10,211	)		(34,901	)		(17,269	)		(160,420	)
Change in value of derivative instruments accounted for as cash flow hedges		3,182			17,326			21,626			175,720
Change in value of available-for-sale securities		10,923			(6,418	)		(98	)		280
		3,894			(23,993	)		4,259			15,580
Comprehensive income		795,436			842,030			266,083			692,861
Less: Comprehensive income attributable to noncontrolling interest		-			-			-			1,142
Comprehensive income attributable to partners	$	795,436		$	842,030		$	266,083		$	691,719

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(Dollars in thousands)

	General Partner			Limited Partners						Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
				Common Unitholders			Class G Unitholders
Balance, August 31, 2006	$	82,450		$	1,647,345		$	-		$	7,067		$	1,857		$	1,738,719
Distributions to partners		(215,770	)		(366,180	)		(40,598	)		-			-			(622,548	)
Issuance of Class G Units to Energy Transfer Equity, LP		-			-			1,200,000			-			-			1,200,000
Conversion to Common Units		-			1,208,394			(1,208,394	)		-			-			-
Capital contribution from General Partner		24,490			-			-			-			-			24,490
Tax effect of remedial income allocation from tax amortization of goodwill		-			(1,161	)		-			-			-			(1,161	)
Non-cash unit-based compensation expense		-			10,471			-			-			-			10,471
Other comprehensive income, net of tax		-			-			-			15,580			-			15,580
Other		-			-			-			-			(760	)		(760	)
Net income		235,876			391,271			48,992			-			1,142			677,281
Balance, August 31, 2007		127,046			2,890,140			-			22,647			2,239			3,042,072
Distributions to partners		(62,897	)		(113,080	)		-			-			-			(175,977	)
Issuance of units in acquisitions		-			1,400			-			-			-			1,400
Issuance of units in public offering		-			234,887			-			-			-			234,887
Capital contribution from General Partner		5,009			-			-			-			-			5,009
Tax effect of remedial income allocation from tax amortization of goodwill		-			(1,161	)		-			-			-			(1,161	)
Units returned by employees for tax withholdings		-			(164	)		-			-			-			(164	)
Non-cash executive compensation		24			1,143			-			-			-			1,167
Non-cash unit-based compensation expense		-			8,114			-			-			-			8,114
Other comprehensive income, net of tax		-			-			-			4,259			-			4,259
Sale of noncontrolling interest and other		-			-			-			-			(2,239	)		(2,239	)
Net income		91,011			170,813			-			-			-			261,824
Balance, December 31, 2007		160,193			3,192,092			-			26,906			-			3,379,191
Distributions to partners		(322,923	)		(556,295	)		-			-			-			(879,218	)
Issuance of units in acquisitions		-			2,228			-			-			-			2,228
Issuance of units in public offering		-			373,059			-			-			-			373,059
Capital contribution from General Partner		7,968			-			-			-			-			7,968
Tax effect of remedial income allocation from tax amortization of goodwill		-			(3,407	)		-			-			-			(3,407	)
Units returned by employees for tax withholdings		-			(3,513	)		-			-			-			(3,513	)
Non-cash executive compensation		25			1,225			-			-			-			1,250
Non-cash unit-based compensation expense		-			23,481			-			-			-			23,481
Other comprehensive income, net of tax		-			-			-			(23,993	)		-			(23,993	)
Net income		315,896			550,127			-			-			-			866,023
Balance, December 31, 2008		161,159			3,578,997			-			2,913			-			3,743,069
Distributions to partners		(355,016	)		(602,239	)		-			-			-			(957,255	)
Issuance of units in acquisitions		-			63,339			-			-			-			63,339
Issuance of units in public offerings		-			936,337			-			-			-			936,337
Capital contributions from General Partner		12,286			-			-			-			-			12,286
Contributions receivable from General Partner		(8,932	)		-			-			-			-			(8,932	)
Distributions on unvested unit awards		-			(2,673	)		-			-			-			(2,673	)
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		-			20,613			-			-			-			20,613
Non-cash executive compensation		25			1,225			-			-			-			1,250
Other comprehensive income loss, net of tax		-			-			-			3,894			-			3,894
Net income		365,362			426,180			-			-			-			791,542
Balance, December 31, 2009	$	174,884		$	4,418,017		$	-		$	6,807		$	-		$	4,599,708

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

6

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	Years Ended December 31,						Four Months Ended December 31, 2007			Year Ended August 31, 2007
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	791,542		$	866,023		$	261,824		$	677,281
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		312,803			262,151			71,333			179,162
Amortization of finance costs charged to interest		8,645			5,886			1,435			4,061
Provision for loss on accounts receivable		2,992			8,015			544			4,229
Goodwill impairment		-			11,359			-			-
Non-cash unit-based compensation expense		24,032			23,481			8,114			10,471
Non-cash executive compensation expense		1,250			1,250			442			-
Deferred income taxes		11,966			(5,280	)		1,003			(4,042	)
(Gains) losses on disposal of assets		1,564			1,303			(14,310	)		6,310
Distributions on unvested awards		(2,673	)		-			-			-
Distributions in excess of (less than) equity in earnings of affiliates, net		3,224			5,621			4,448			(5,161	)
Other non-cash		(4,468	)		3,382			(2,069	)		(761	)
Net change in operating assets and liabilities, net of effects of acquisitions		(323,999	)		74,954			(87,062	)		241,182
Net cash provided by operating activities		826,878			1,258,145			245,702			1,112,732
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, net		(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		3,475,107			6,015,461			1,741,547			4,757,971
Principal payments on debt		(2,954,737	)		(4,699,123	)		(1,062,272	)		(4,260,494	)
Net proceeds from issuance of Limited Partner Units		936,337			373,059			234,887			1,200,000
Capital contribution from General Partner		3,354			7,968			29			24,490
Distributions to partners		(957,255	)		(879,218	)		(175,977	)		(622,548	)
Debt issuance costs		(7,647	)		(25,272	)		(211	)		(11,397	)
Net cash provided by financing activities		495,159			792,875			738,003			1,088,022
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(23,719	)		35,435			(12,238	)		42,664
CASH AND CASH EQUIVALENTS, beginning of period		91,902			56,467			68,705			26,041
CASH AND CASH EQUIVALENTS, end of period	$	68,183		$	91,902		$	56,467		$	68,705

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

7

ENERGY TRANSFER PARTNERS, 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 Partners, L.P. and subsidiaries (the “Partnership” or “ETP”) 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. 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 originally issued.

We are managed by our general partner, Energy Transfer Partners GP, L.P. (our “General Partner” or “ETP GP”), which is in turn managed by its general partner, Energy Transfer Partners, L.L.C. (“ETP LLC”). Energy Transfer Equity, L.P., a publicly traded master limited partnership (“ETE”), owns ETP LLC, the general partner of our General Partner.

The consolidated financial statements of the Partnership presented herein include our operating 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

8

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

In order to simplify the obligations of Energy Transfer Partners, L.P. 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:

_Ÿ 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.

_Ÿ 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.

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

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

_Ÿ 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.

_Ÿ 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,” “ETP,” “Energy Transfer” or the “Partnership.”

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

9

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.

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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.

11

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.

12

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, 2007			Year Ended August  31, 2007
	2009			2008
Accounts receivable	$	28,431		$	220,635		$	(169,263	)	$	54,347
Accounts receivable from related companies		(29,042	)		6,849			(12,557	)		(6,003	)
Inventories		(101,592	)		96,145			(168,430	)		196,173
Exchanges receivable		22,074			(7,888	)		(4,216	)		(3,406	)
Other current assets		8,155			(57,041	)		(4,701	)		53,597
Intangibles and other assets		(4,836	)		(40,802	)		605			(1,867	)
Accounts payable		(16,024	)		(296,185	)		195,644			(92,172	)
Accounts payable to related companies		4,459			(13,957	)		29,012			18,564
Exchanges payable		(35,433	)		14,254			6,117			3,000
Accrued and other current liabilities		(123,362	)		32,377			977			(27,458	)
Interest payable		29,963			42,952			33,408			14,844
Other long-term liabilities		1,401			1,741			(680	)		1,460
Price risk management liabilities, net		(108,193	)		75,874			7,022			30,103
Net change in assets and liabilities, net of effect of acquisitions	$	(323,999	)	$	74,954		$	(87,062	)	$	241,182

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

	Years Ended December 31,				Four Months Ended December 31, 2007		Year Ended August  31, 2007
	2009		2008
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
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
Issuance of common units in connection with certain acquisitions	$	63,339	$	2,228	$	1,400	$	-
Capital contribution receivable from General Partner	$	8,932	$	-	$	-	$	-
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized	$	367,924	$	237,620	$	51,465	$	184,993
Cash paid for income taxes	$	15,447	$	4,674	$	9,009	$	8,583

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.

13

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.

Our 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.

Our 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.

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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, 2007			Year Ended August  31, 2007
	2009			2008
Balance, beginning of 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.

15

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		68,679		75,215
Total other current assets	$	148,373	$	153,452

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 our 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.

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

	December 31, 2009			December 31, 2008
Land and improvements	$	87,224		$	74,731
Buildings and improvements (10 to 40 years)		156,676			129,714
Pipelines and equipment (10 to 83 years)		6,933,189			5,136,357
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)		509,173			358,669
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
		9,410,250			7,287,894
Less – Accumulated depreciation		(979,158	)		(700,826	)
		8,431,092			6,587,068
Plus – Construction work-in-process		239,155			1,709,017
Property, plant and equipment, net	$	8,670,247		$	8,296,085

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, 2007		Year Ended August 31, 2007
	2009		2008
Depreciation expense	$	291,908	$	244,689	$	64,569	$	163,630
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.

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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, December 31, 2007	$	10,327	$	98,613	$	24,368		$	594,801		$	-	$	728,109
Purchase accounting adjustments		-		-		-			2,457			-		2,457
Goodwill acquired		-		-		9,141			15,346			-		24,487
Goodwill Impairment		-		-		(11,359	)		-			-		(11,359	)
Balance, December 31, 2008		10,327		98,613		22,150			612,604			-		743,694
Purchase accounting adjustments		-		-		-			(8,662	)		-		(8,662	)
Goodwill acquired		-		-		-			33			10,440		10,473
Balance December 31, 2009	$	10,327	$	98,613	$	22,150		$	603,975		$	10,440	$	745,505

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)		68,597		(24,774	)		59,108		(16,586	)
Regulatory assets		101,879		(9,501	)		98,560		(5,941	)
Other		41,316		-			43,153		-
Total intangibles and other long-term assets	$	489,842	$	(105,883	)	$	486,818	$	(92,619	)

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

	Years Ended December 31,				Four Months Ended December 31,     2007		Year Ended August 31,     2007
	2009		2008
Reported in depreciation and amortization	$	20,895	$	17,462	$	6,764	$	15,532
Reported in interest expense	$	8,188	$	6,008	$	1,710	$	4,502

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

Years Ending December 31:
2010	$	26,991
2011		25,326
2012		21,740
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		25,202		64,692
Taxes other than income taxes		23,294		20,772
Income taxes payable		3,401		14,538
Deferred income taxes		-		589
Other		42,485		73,294
Total accrued and other current liabilities	$	228,946	$	433,794

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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 $6.75 billion and $6.22 billion, respectively. At December 31, 2008, the aggregate fair value and carrying amount of long-term debt was $5.10 billion and $5.66 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:

Description	Fair Value Measurements at December 31, 2009 Using									Fair Value Measurements at December 31, 2008 Using
	Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)
Assets:
Marketable securities	$	6,055		$	6,055		$	-		$	5,915		$	5,915	$	-
Natural gas 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		-			-			-			(51,642	)		-		(51,642	)
	$	186,674		$	174,727		$	11,947		$	22,450		$	112,005	$	(89,555	)

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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, 2007		Year Ended August  31, 2007
	2009			2008
Received and netted against project costs	$	6,453		$	50,050	$	3,493	$	10,463
Recorded in other income		(305	)		8,352		216		403
Totals	$	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 government authorities on a net basis.

Income Taxes

Energy Transfer Partners, L.P. 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,

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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. This termination did not affect our classification as a partnership for federal income tax purposes or otherwise affect the nature or extent of our “qualifying income” for federal income tax purposes. This termination required us to close our taxable year, make new elections as to various tax matters and reset the depreciation schedule for our depreciable assets for federal income tax purposes. The resetting of our depreciation schedule resulted in a deferral of the depreciation deductions allowable in computing the taxable income allocated to our Unitholders. However, certain elections we made in connection with this tax termination allowed us to utilize deductions for the amortization of certain intangible assets for purposes of computing the taxable income allocable to certain of our Unitholders, which deductions had not previously been utilized in computing taxable income allocable to our 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, our subsidiary, Heritage Holdings, Inc. (“HHI”), which owns our 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 our Common Units. The amount of such “goodwill” accumulated as of the date of our 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. We account for HHI using the treasury stock method due to its ownership of our Class E units. We account for the tax effects of the goodwill amortization and remedial income allocation as an adjustment of our HHI purchase price allocation, which effectively results in a charge to our 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.

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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:

_Ÿ 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.

_Ÿ 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.

_Ÿ 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

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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. See Note 12 for additional information related to interest rate derivatives.

Allocation of Income (Loss)

For purposes of maintaining partner capital accounts, the 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). Normal allocations according to percentage interests are made after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to the General Partner.

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 distributions based on the most recently declared distributions as of the grant date.

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New Accounting Standards

A retrospective adjustment has been made to prior period income per limited partner unit presented in our consolidated statements of operations to conform to current period presentation as discussed further below.

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 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 new 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 position presentation.

Upon adoption, we reclassified $1.1 million of minority interest expense to net income attributable to noncontrolling interest in our consolidated statements of operations for 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.

Based on the terms of our Partnership Agreement, the new methodology requires us to allocate any excess undistributed earnings to the general partner and limited partners based on their respective ownership interests, with none of the excess undistributed earnings allocated to the incentive distribution rights (“IDRs”). Previously, we allocated a portion of the excess undistributed earnings to the IDRs. Thus, for periods where earnings exceed distributions, the new methodology will result in a higher income per limited partner unit than our previous approach. For periods where distributions exceed earnings, the new methodology is consistent with our previous approach.

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 260-10-45. 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.

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The following financial table sets forth the effect of the retrospective application of the new methodology under ASC 260-10-55 and ASC 260-10-45:

	Year Ended December 31, 2008				Four Months Ended December 31, 2007				Year Ended August 31, 2007
	Originally Reported		As Adjusted		Originally Reported		As Adjusted		Originally Reported		As Adjusted
Basic net income per limited partner unit	$	3.75	$	3.74	$	1.22	$	1.24	$	3.32	$	3.32
Diluted net income per limited partner unit	$	3.74	$	3.74	$	1.21	$	1.24	$	3.31	$	3.31

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:

_Ÿ Acquisition costs are generally expensed as incurred;

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

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

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

_Ÿ 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

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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 our issuance of 1,450,076 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, we 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

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2007

On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), we acquired the member interests in CCE Holdings, LLC (“CCEH”) from GE and certain other investors for $1.00 billion. We financed a portion of the CCEH purchase price with the proceeds from our issuance of 26,086,957 Class G Units to ETE 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 our interstate transportation segment.

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, we acquired two small natural gas gathering systems in east and north Texas for an aggregate purchase price of $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, we 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 50% member interests in CCEH, our acquisitions 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.

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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
Other		9,329
Total Regulatory Assets acquired	$	69,957

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

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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

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

We are 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

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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, 2007		Year Ended August 31, 2007
	2009		2008
Revenue	$	98,593	$	-	$	-	$	-
Operating income		47,818		-		-		-
Net income		36,555		1,057		-		-

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

5. NET INCOME PER LIMITED PARTNER UNIT:

Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. As discussed in Note 2, the adoption of a new accounting principle required us to change our calculation of earnings per unit during periods where earnings exceeded distributions; earnings in excess of distributions are now allocated to the General Partner and Limited Partners based on their respective ownership interests. Previously, a portion of earnings in excess of distributions had been allocated to the General Partner with respect to the IDRs. We have applied this change in accounting principle retrospectively; therefore, earnings per unit amounts for prior periods have been restated.

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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, 2007		Year Ended August 31, 2007
	2009			2008
Net income attributable to partners	$	791,542		$	866,023		$	261,824	$	676,139
General Partner’s interest in net income		365,362			315,896			91,011		235,876
Limited Partner’s interest in net income		426,180			550,127			170,813		440,263
Additional earnings allocated from General Partner		468			-			-		-
Distributions on employee unit awards, net of allocation to General Partner		(2,760	)		(153	)		-		-
Net income available to Limited Partners	$	423,888		$	549,974		$	170,813	$	440,263
Weighted average Limited Partner units – basic		167,337,192			146,871,261			137,624,934		132,618,053
Basic net income per Limited Partner unit	$	2.53		$	3.74		$	1.24	$	3.32
Weighted average Limited Partner units		167,337,192			146,871,261			137,624,934		132,618,053
Dilutive effect of Unit Grants		431,789			219,347			388,432		259,099
Weighted average Limited Partner units, assuming dilutive effect of Unit Grants		167,768,981			147,090,608			138,013,366		132,877,152
Diluted net income per Limited Partner unit	$	2.53		$	3.74		$	1.24	$	3.31

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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:
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		2,224			2,565		Due in installments through 2024.
Unamortized discounts		(12,829	)		(13,477	)
		6,217,805			5,663,747
Current maturities		(40,887	)		(45,198	)
	$	6,176,918		$	5,618,549

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

2010	$	40,887
2011		44,567
2012		572,838
2013		372,523
2014		443,519
Thereafter		4,743,471
	$	6,217,805

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 the Partnership and the obligation of the Partnership to repay the ETP Senior Notes is not guaranteed by any of the Partnership’s subsidiaries. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ours or our 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 our 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”).

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Revolving Credit Facilities

ETP Credit Facility

The ETP Credit Facility provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity, under the Amended and Restated Credit Agreement). The ETP Credit Facility matures on July 20, 2012, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating and the fee is 0.11% based on our current rating with a maximum fee of 0.125%.

As of 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 the HOLP Notes and the HOLP Credit Facility contain customary restrictive covenants applicable to 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 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:

_Ÿ incur indebtedness;

_Ÿ grant liens;

_Ÿ enter into mergers;

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_Ÿ dispose of assets;

_Ÿ make certain investments;

_Ÿ 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);

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

_Ÿ engage in transactions with affiliates;

_Ÿ enter into restrictive agreements; and

_Ÿ 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 we make 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 our ability to make cash distributions to our Unitholders, our general partner and the holder of our 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 we were in compliance with all requirements, limitations, and covenants related to our debt agreements as of December 31, 2009.

7. PARTNERS’ CAPITAL

Limited Partner Units

Limited Partner interests are represented by Common and Class E Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. As of December 31, 2009, there were issued and outstanding 179,274,747 Common Units representing an aggregate 98.1% Limited Partner

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interest in us. There are also 8,853,832 Class E Units outstanding that are reported as treasury units, which units are entitled to receive distributions in accordance with their terms.

No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as these equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.

IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP owns all of the IDRs.

Common Units

The change in Common Units is as follows:

	Years Ended December 31,		Four Months Ended December 31, 2007	Year Ended August 31, 2007
	2009	2008
Number of Units, beginning of period	152,102,471	142,069,957	136,981,221	110,726,999
Common Units issued in connection with public offerings	23,575,000	9,662,500	5,000,000	-
Common Units issued in connection with certain acquisitions	1,450,076	53,893	27,348	-
Common Units issued in connection with the Equity Distribution Agreement	1,891,691
Issuance of restricted Common Units	-	-	-	167,265
Conversion of Class G Units to Common Units	-	-	-	26,086,957
Issuance of Common Units under the equity incentive plans	255,509	316,121	61,388	-
Number of Units, end of period	179,274,747	152,102,471	142,069,957	136,981,221

Our Common Units are registered under the Securities Act of 1934 and are listed for trading on the 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 our 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.”

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Public Offerings

The following table summarizes our public offerings of Common Units, all of which have been registered under the Securities Act of 1933, as amended:

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.

Equity Distribution Program

On August 26, 2009, we entered into an Equity Distribution Agreement with UBS Securities LLC (“UBS”). Pursuant to this agreement, we may offer and sell from time to time through UBS, as our sales agent, 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 us and UBS. Under the terms of this agreement, we may also sell Common Units to UBS as principal for its own account at a price agreed upon at the time of sale. Any sale of Common Units to UBS as principal would be pursuant to the terms of a separate agreement between us and UBS. During 2009, we issued 2,079,593 of our 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 our revolving credit facility.

Equity Incentive Plan Activity

As discussed in Note 8, we issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.

Other Common Unit Activity

On November 1, 2006, we issued 26,086,957 Class G Units to ETE for aggregate proceeds of $1.20 billion in order to fund a portion of the Transwestern Acquisition and to repay indebtedness we incurred in connection with the Titan acquisition. During fiscal year 2007, we converted all of the Class G Units to Common Units.

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Class E Units

There are 8,853,832 Class E Units outstanding that are reported as treasury units. These Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. Management plans to leave the Class E Units in the form described here indefinitely. In the event of our termination and liquidation, the Class E Units will be allocated 1% of any gain upon liquidation and will be allocated any loss upon liquidation to the same extent as Common Units. After the allocation of such amounts, the Class E Units will be entitled to the balance in their capital accounts, as adjusted for such termination and liquidation. The terms of the Class E Units were determined in order to provide us with the opportunity to minimize the impact of our ownership of Heritage Holdings, including the $57.4 million in deferred tax liabilities of Heritage Holdings that were included in the purchase of Heritage Holdings. The Class E Units are treated as treasury stock for accounting purposes because they are owned by our wholly-owned subsidiary, Heritage Holdings. Due to the ownership of the Class E Units by this corporate subsidiary, the payment of distributions on the Class E Units will result in annual tax payments by Heritage Holdings at corporate federal income tax rates, which tax payments will reduce the amount of cash that would otherwise be available for distribution to us as the owner of Heritage Holdings. Because distributions on the Class E Units will be available to us as the owner of Heritage Holdings, those funds will be available, after payment of taxes, for general partnership purposes, including to satisfy working capital requirements, for the repayment of outstanding debt and to make distributions to the Unitholders. Because the Class E Units are not entitled to receive any allocation of Partnership income, gain, loss, deduction or credit that is attributable to our ownership of Heritage Holdings, such amounts will instead be allocated to the General Partner in accordance with its respective interest and the remainder to all Unitholders other than the holders of Class E Units pro rata. In the event that Partnership distributions exceed $1.41 per unit annually, all such amounts in excess thereof will be available for distribution to Unitholders other than the holders of Class E Units in proportion to their respective interests.

Quarterly Distributions of Available Cash

The Partnership Agreement requires that we distribute all of our Available Cash to our Unitholders and our 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 of our fiscal quarters, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of our 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 our Partnership Agreement.

Our distributions from operating surplus for any quarter in an amount equal to 100% of Available Cash will generally be made as follows, subject to the payment of incentive distributions to the General Partner to the extent that certain target levels of quarterly cash distributions are achieved ($0.275 per unit):

_Ÿ First, 100% to all Common and Class E Unitholders and the General Partner, in accordance with their percentage interests, until each Common Unit has received $0.25 per unit for such quarter (the “minimum quarterly distribution”);

_Ÿ Second, 100% to all Common and Class E Unitholders and the General Partner, in accordance with their percentage interests, until each Common Unit has received $0.275 per unit for such quarter (the “first target distribution”);

_Ÿ Third, 87% to all Common and Class E Unitholders and the General Partner, in accordance with their percentage interests, 13% to the holders of IDRs, pro rata, until each Common Unit has received at least $0.3175 per unit for such quarter (the “second target distribution”);

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_Ÿ Fourth, 77% to all Common and Class E Unitholders and the General Partner, in accordance with their percentage interests, 23% to the holders of IDRs, pro rata, until each Common Unit has received at least $0.4125 per unit for such quarter; (the “third target distribution”); and

_Ÿ Fifth, thereafter, 52% to all Common and Class E Unitholders and the General Partner, in accordance with their percentage interests, 48% to the holders of Incentive Distribution Rights, pro rata.

The allocation of distributions among the Common and Class E Unitholders and the General Partner is based on their respective interests as of the record date for such distributions. As of December 31, 2009, the Common and Class E Unitholders collectively held 98.1% of the ownership interests in us, and the General Partner held a 1.9% interest.

Notwithstanding the foregoing, any arrearage in the payment of the minimum quarterly distribution for all prior quarters and the distributions on each Class E unit may not exceed $1.41 per year.

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 our 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. This distribution was paid on February 14, 2008 to Unitholders of record as of the close of business on February 1, 2008.

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

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The total amounts of 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 as follows (all from Available Cash from our operating surplus and are shown in the year with respect to which they relate):

	Years Ended December 31,				Four Months Ended December 31, 2007		Year Ended August 31, 2007
	2009		2008
Limited Partners -
Common Units	$	629,263	$	537,731	$	160,672	$	396,095
Class E Units (1)		12,484		12,484		3,121		12,484
Class G Units (2)		-		-		-		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

(1) See explanation of Class E Units above.

(2) Distributions declared prior to the Class G Units converting to Common Units (see detail above).

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

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 gain (loss) on interest rate hedges		(125	)		161
Unrealized gains (losses) on available-for-sale securities		4,941			(5,983	)
Total AOCI, net of tax	$	6,807		$	2,913

8. UNIT-BASED COMPENSATION PLANS:

We have issued equity awards to employees and directors under the following plans:

_Ÿ 2008 Long-Term Incentive Plan.    On December 16, 2008, ETP Unitholders approved the ETP 2008 Long-Term Incentive Plan (the “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 our board of directors. Up to 5,000,000 ETP Common Units may be granted as awards under the 2008 Incentive Plan, with such amount subject to adjustment as provided for under the terms of the 2008 Incentive Plan. The 2008 Incentive Plan is effective until December 16, 2018 or, if earlier, the time which all available units under the 2008 Incentive Plan have been issued to participants or the time of termination of the plan by our board of directors. As of December 31, 2009, a total of 4,213,111 ETP Common Units remain available to be awarded under the 2008 Incentive Plan.

_Ÿ 2004 Unit Plan.    Our Amended and Restated 2004 Unit Award Plan (the “2004 Unit Plan”) provides for awards of up to 1,800,000 ETP Common Units and other rights to our 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 2004 Unit Plan. As of December 31, 2009, 5,578 ETP Common Units were available for future grants under the 2004 Unit Plan.

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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 our 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 our 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 our 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 our units for the year plus the aggregate per unit cash distributions received for the year. Non-cash compensation expense is recorded for these 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 our 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 employee unit awards including unit awards granted to our executive officers.

Commencing in December 2007, we have 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 our 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 Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our 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, we 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 our equity incentive plans, our 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.

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Award Activity

The following table shows the activity of the 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 the President of the entity that owns our General Partner, awarded to certain officers of ETP certain rights related to units of ETE previously issued by ETE to such officers. 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.

We are 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, we 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.

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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, 2007		Year Ended August 31, 2007
	2009			2008
Current expense (benefit):
Federal	$	(8,851	)	$	(180	)	$	2,990	$	7,896
State		9,662			12,216			5,705		9,803
Total		811			12,036			8,695		17,699
Deferred expense (benefit):
Federal		11,541			(5,634	)		1,482		(4,598	)
State		425			278			612		557
Total		11,966			(5,356	)		2,094		(4,041	)
Total income tax expense (benefit)	$	12,777		$	6,680		$	10,789	$	13,658

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, 2007		Year Ended August 31, 2007
	2009		2008
Federal statutory tax rate	35.00	%	35.00	%	35.00	%	35.00	%
State income tax rate, net of federal benefit	1.03	%	1.25	%	1.82	%	1.25	%
Earnings not subject to tax at the Partnership level	(34.44	%)	(35.48	%)	(32.86	%)	(34.25	%)
Effective tax rate	1.59	%	0.77	%	3.96	%	2.00	%

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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, 2009		December 31, 2008
Property, plant and equipment	$	112,707	$	105,032
Other, net		290		(3,846	)
Total deferred tax liability		112,997		101,186
Less current deferred tax liability		-		589
Total long-term deferred tax liability	$	112,997	$	100,597

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, 2007		Year Ended August  31, 2007
	2009		2008
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.

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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

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

The commitment amount under the MEP Facility was 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 us 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. Our contingent obligations with respect to our 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%.

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FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). We have guaranteed 50% of the obligations of FEP under the FEP Facility, with the remaining 50% of FEP Facility obligations guaranteed by KMP. Subject to certain exceptions, our guarantee may be proportionately increased or decreased if our ownership percentage increases or decreases. The FEP Facility is available through May 11, 2012. Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or 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. Our contingent obligation with respect to our 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 believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $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

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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 quarters of 2009 and 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 our investment in M-P Energy in October 2007, we 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 coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

FERC/CFTC and Related Matters.  On July 26, 2007, the FERC issued to us an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that we violated FERC rules and regulations. The FERC alleged that we 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 our commodities derivatives positions and from certain of our index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods we violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the NGA. The FERC alleged that we 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 we manipulated daily prices at the

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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, our 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, we entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against us and, on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement settles all outstanding FERC claims against us and provides that we 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 us, including existing litigation claims as well as any new claims that may be asserted against this fund. An administrative law judge appointed by the FERC will determine the validity of any third party claim against this fund. Any party who receives money from this fund will be required to waive all claims against us 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 we do not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with our alleged conduct related to the FERC claims. The settlement agreement also requires us 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 ETE 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 ETE 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 ETE contains an additional allegation that we and ETE transported gas in a manner that favored our affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. We have moved to compel arbitration and/or contested subject-matter jurisdiction in some of these cases. In one of these cases, the Texas Supreme Court ruled on July 3, 2009 that the state district court erred in ruling that a plaintiff was entitled to pre-arbitration discovery and therefore remanded to the state district court with a direction to rule on our original motion to compel arbitration pursuant to the terms of the arbitration clause in a natural gas contract between us and the plaintiff. This plaintiff has filed a motion with the Texas Supreme Court requesting a rehearing of the ruling.

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

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A consolidated class action complaint has been filed against us in the United States District Court for the Southern District of Texas. This action alleges that we 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, we had the market power to manipulate index prices, and that we 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 our natural gas physical and financial trading positions, and that we intentionally submitted price and volume trade information to trade publications. This complaint also alleges that we violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by us 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, we 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, we 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 Fifth Circuit.

On March 17, 2008, a second class action complaint was filed against us in the United States District Court for the Southern District of Texas. This action alleges that we 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 we exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit our 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, we 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. We opposed the motion and cross-moved to dismiss. On August 7, 2009, the court denied the plaintiff’s motion and granted our 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 Fifth Circuit.

We are expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. We record accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, we made the $5.0 million payment and established the $25.0 million fund in October 2009. We expect the after-tax cash impact of the settlement to be less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims, which we expect to realize in future periods. 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 we become 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, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obliged to pay as a

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result of the final resolution of these matters is greater than the amount of our accrual for these matters. As our 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 our cash available to service our indebtedness either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations and our 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.

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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

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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.

Our 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

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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 us 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/Ethane	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 have previously managed a portion of our current and future interest rate exposures by utilizing interest rate swaps. As of December 31, 2009, we do not have any interest rate swaps outstanding.

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In December 2009, we settled forward starting swaps with notional amounts of $500.0 million for a cash payment of $11.1 million. In April 2009, we terminated forward starting swaps with notional amounts of $100.0 million and $150.0 million for an insignificant amount.

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	)
Total derivatives designated as hedging instruments		$	9,112	$	11,583	$	(24,236	)	$	(1,623	)
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		-		-		-			(51,643	)
Total derivatives not designated as hedging instruments		$	76,779	$	449,858	$	(37,191	)	$	(443,282	)
Total derivatives		$	85,891	$	461,441	$	(61,427	)	$	(444,905	)

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.

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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, 2007			Year Ended August  31, 2007
		2009		2008
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		-		-			-			(4,719	)
Total		$	3,143	$	17,461		$	21,406		$	177,046
	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, 2007			Year Ended August  31, 2007
		2009		2008
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		287		646			(51	)		920
Total		$	10,211	$	43,520		$	8,622		$	163,260
	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, 2007			Year Ended August 31, 2007
		2009		2008
Derivatives in cash flow hedging relationships:
Commodity Derivatives	Cost of Products Sold	$	-	$	(8,347	)	$	8,472		$	183
Interest Rate Swap Derivatives	Interest Expense		-		-			-			(1,813	)
Total		$	-	$	(8,347	)	$	8,472		$	(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, 2007			Year Ended August 31, 2007
		2009		2008
Derivatives in fair value hedging relationships:
Commodity Derivatives (including hedged items)	Cost of Products Sold	$	60,045	$	-		$	-		$	-
Total		$	60,045	$	-		$	-		$	-

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	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, 2007			Year Ended August 31, 2007
		2009		2008
Derivatives not designated as hedging instruments:
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		39,239		(50,989	)		(1,013	)		31,032
Total		$	139,046	$	(66,794	)	$	6,575		$	66,288

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:

We sponsor 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.

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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 ETE’s General Partner, LE GP, LLC (“LE GP”). 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 ETE’s 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, 2007				Year Ended August 31, 2007
		2009				2008
	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

58

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
ETP GP	$	221	$	122
ETE		5,255		2,632
MEP		632		2,805
McReynolds Energy		-		202
Energy Transfer Technologies, Ltd.		-		16
Others		870		449
Total accounts receivable from related companies excluding Enterprise	$	6,978	$	6,226

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 our General Partner’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.

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The Chief Executive Officer (“CEO”) of our 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:

_Ÿ natural gas operations:

^¡ intrastate transportation and storage

^¡ interstate transportation

^¡ midstream

_Ÿ 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.

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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, 2007		Year Ended August 31, 2007
	2009		2008
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

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

	Years Ended December 31,						Four  Months Ended December 31, 2007			Year Ended August 31, 2007
	2009			2008
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 - revenues from external customers		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			16,702			6,060			121,278
Intersegment revenues		1,145			-			-			-
		21,665			16,702			6,060			121,278
Eliminations		(999,870	)		(3,568,065	)		(664,522	)		(1,562,199	)
Total revenues	$	5,417,295		$	9,293,868		$	2,349,510		$	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	$	107,605		$	84,701		$	20,670		$	56,145
Interstate transportation		48,297			37,790			12,305			27,972
Midstream		70,845			59,344			13,629			23,388
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	$	312,803		$	262,151		$	71,333		$	179,162
Operating income (loss):
Intrastate transportation and storage	$	626,779		$	718,348		$	172,120		$	488,098
Interstate transportation		138,233			124,676			29,657			95,650
Midstream		140,732			166,414			73,167			123,176
Retail propane and other retail propane related		229,229			114,564			46,747			124,263
All other		(8,658	)		(1,531	)		(628	)		1,735
Selling general and administrative expenses not allocated to segments		1,292			(4,892	)		2,571			(3,270	)
Total operating income	$	1,127,607		$	1,117,579		$	323,634		$	829,652
Other items not allocated by segment:
Interest expense, net of interest capitalized	$	(394,274	)	$	(265,701	)	$	(66,298	)	$	(175,563	)
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		39,239			(50,989	)		(1,013	)		31,032
Allowance for equity funds used during construction		10,557			63,976			7,276			4,948
Other, net		2,157			9,306			(5,202	)		2,019
Income tax expense		(12,777	)		(6,680	)		(10,789	)		(13,658	)
		(336,065	)		(251,556	)		(61,810	)		(152,371	)
Net income	$	791,542		$	866,023		$	261,824		$	677,281

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	As of December 31,						As of August 31, 2007
	2009		2008		2007
Total assets:
Intrastate transportation and storage	$	4,901,102	$	4,642,430	$	3,976,895	$	3,534,013
Interstate transportation		3,313,837		2,487,078		1,834,941		1,653,363
Midstream		1,523,538		1,537,972		1,304,187		801,968
Retail propane and other retail propane related		1,784,353		1,810,953		1,778,426		1,593,863
All other		212,142		149,056		113,712		125,221
Total	$	11,734,972	$	10,627,489	$	9,008,161	$	7,708,428
	Years Ended December 31,				Four Months Ended December 31, 2007		Year Ended August 31, 2007
	2009		2008
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. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts. 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.

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	Quarter Ended									Total Year
2009:	March 31		June 30		September 30			December 31
Revenues	$	1,630,100	$	1,151,817	$	1,129,596		$	1,505,782	$	5,417,295
Gross profit		670,961		525,824		451,448			647,006		2,295,239
Operating income		360,853		219,220		177,347			370,187		1,127,607
Net income		307,167		150,738		72,456			261,181		791,542
Limited Partners’ interest in net income		216,877		63,559		(16,471	)		162,215		426,180
Basic net income per limited partner unit	$	1.37	$	0.38	$	(0.10	)	$	0.92	$	2.53
Diluted net income per limited partner unit	$	1.37	$	0.38	$	(0.10	)	$	0.91	$	2.53
	Quarter Ended									Total Year
2008:	March 31		June 30		September 30			December 31
Revenues	$	2,639,371	$	2,653,476	$	2,206,215		$	1,794,806	$	9,293,868
Gross profit		659,653		529,404		572,761			593,970		2,355,788
Operating income		373,486		225,829		260,508			257,756		1,117,579
Net income		328,335		165,674		221,048			150,966		866,023
Limited Partners’ interest in net income		253,971		86,691		140,796			68,669		550,127
Basic net income per limited partner unit	$	1.78	$	0.61	$	0.94		$	0.45	$	3.74
Diluted net income per limited partner unit	$	1.77	$	0.60	$	0.94		$	0.45	$	3.74

For the three months ended September 30, 2009, distributions paid for the period exceeded net income by $177.0 million. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.

17. 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.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

	Four Months Ended December 31,
	2007			2006
	As Adjusted			As Adjusted
REVENUES:
Natural gas operations	$	1,832,192		$	1,668,667
Retail propane		471,494			409,821
Other		45,824			83,978
Total revenues		2,349,510			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		71,333			48,767
Selling, general and administrative		59,132			40,603
Total costs and expenses		2,025,876			1,952,578
OPERATING INCOME		323,634			209,888
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(66,298	)		(54,946	)
Equity in earnings (losses) of affiliates		(94	)		4,743
Gain on disposal of assets		14,310			2,212
Other, net		1,061			2,158
INCOME BEFORE INCOME TAX EXPENSE		272,613			164,055
Income tax expense		10,789			3,120
NET INCOME		261,824			160,935
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		-			490
NET INCOME ATTRIBUTABLE TO PARTNERS		261,824			160,445
GENERAL PARTNER’S INTEREST IN NET INCOME		91,011			73,204
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	170,813		$	87,241
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	1.24		$	0.70
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		137,624,934			123,931,608
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	1.24		$	0.70
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		138,013,366			124,229,968

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

	Four Months Ended December 31,
	2007			2006
Net income	$	261,824		$	160,935
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		(17,269	)		(23,698	)
Change in value of derivative instruments accounted for as cash flow hedges		21,626			152,653
Change in value of available-for-sale securities		(98	)		(401	)
		4,259			128,554
Comprehensive income		266,083			289,489
Less: Comprehensive income attributable to noncontrolling interest		-			490
Comprehensive income attributable to partners	$	266,083		$	288,999

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ENERGY TRANSFER PARTNERS, 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	$	261,824		$	160,935
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		71,333			48,767
Amortization in interest expense		1,435			1,068
Provision for loss on accounts receivable		544			563
Non-cash unit-based compensation expense		8,114			4,385
Non-cash executive compensation		442			-
Deferred income taxes		1,003			(2,234	)
Gain on disposal of assets		(14,310	)		(2,212	)
Distributions in excess of (less than) equity in earnings of affiliates, net		4,448			(4,743	)
Other non-cash		(2,069	)		(76	)
Net change in operating assets and liabilities, net of acquisitions		(87,062	)		214,457
Net cash provided by operating activities		245,702			420,910
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		1,741,547			1,667,810
Principal payments on debt		(1,062,272	)		(1,737,788	)
Net proceeds from issuance of Limited Partner Units		234,887			1,200,000
Capital contribution from General Partner		29			24,489
Distributions to partners		(175,977	)		(125,774	)
Debt issuance costs		(211	)		(9,451	)
Net cash provided by financing activities		738,003			1,019,286
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(12,238	)		96,015
CASH AND CASH EQUIVALENTS, beginning of period		68,705			26,041
CASH AND CASH EQUIVALENTS, end of period	$	56,467		$	122,056
NON-CASH INVESTING AND FINANCING ACTIVITIES SUPPLEMENTAL CASH FLOW INFORMATION:
NON-CASH INVESTING ACTIVITIES:
Capital expenditures accrued	$	87,622		$	13,294
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	$	51,465		$	27,496
Cash paid during the period for income taxes	$	9,009		$	6,196

67